<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, 1999
                                      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 Securities 3
6.875% Cumulative Quarterly Income Preferred Securities 4

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

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 Securities 5
7.60% Trust Originated Preferred Securities 6

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

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 Securities 7           7.60% Trust Preferred Securities 8
7.75% Cumulative Quarterly Income Preferred Securities 9
6.85% Trust Preferred Securities 10


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

===============================================================================
--------
1 As of December 31, 1999.
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           Gulf Power Company
redeemable preferred securities,
$25 liquidation amount
7.625% Cumulative Quarterly Income Preferred Securities 11
7.00% Cumulative Quarterly Income Preferred Securities 12

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

Depositary preferred shares, each     Mississippi Power Company
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 Securities 13

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

Company obligated mandatorily         Savannah Electric and Power Company
redeemablepreferred securities,
$25 liquidation amount
6.85% Trust Preferred Securities 14

         Securities registered pursuant to Section 12(g) of the Act:15

Title of each class                                       Registrant

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

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

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

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

Preferred stock, cumulative, $100 stated value            Georgia Power Company
$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 Mississippi Power Capital Trust I and guaranteed by Mississippi
   Power Company.
14 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah
   Electric and Power Company.
15 As of December 31, 1999.


<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% Series4.60% Series
4.72% Series7.00% 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 29, 2000: $14.4 billion. Each of such other
registrants is a wholly-owned subsidiary of The Southern Company and has no
voting stock other than its common stock. A description of registrants' common
stock follows:
<TABLE>
<CAPTION>

                                                   Description of                      Shares Outstanding
Registrant                                          Common Stock                      at February 29, 2000

<S>                                          <C>                                             <C>
The Southern Company                         Par Value $5 Per Share                          649,563,507
Alabama Power Company                        Par Value $40 Per Share                           5,608,955
Georgia Power Company                        No Par Value                                      7,761,500
Gulf Power Company                           No Par Value                                        992,717
Mississippi Power Company                    Without Par Value                                 1,121,000
Savannah Electric and Power Company          Par Value $5 Per Share                           10,844,635
</TABLE>

             Documents incorporated by reference: specified portions of The
Southern Company's Proxy Statement relating to the 2000 Annual Meeting of
Stockholders 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

<S>                                                                                                                      <C>
Item 1         Business
                  The SOUTHERN System..................................................................................  I-2
                  Integrated Southeast Utilities.......................................................................  I-2
                  Southern Energy......................................................................................  I-2
                  Other Business.......................................................................................  I-3
                  Certain Factors Affecting the Industry...............................................................  I-3
                  Construction Programs................................................................................  I-4
                  Year 2000............................................................................................  I-5
                  Financing Programs...................................................................................  I-6
                  Fuel Supply..........................................................................................  I-7
                  Territory Served by the Integrated Southeast Utilities...............................................  I-9
                  Competition..........................................................................................  I-12
                  Regulation...........................................................................................  I-13
                  Rate Matters.........................................................................................  I-15
                  Employee Relations...................................................................................  I-17
Item 2          Properties.............................................................................................  I-18
Item 3          Legal Proceedings......................................................................................  I-24
Item 4          Submission of Matters to a Vote of Security Holders....................................................  I-24
                Executive Officers of SOUTHERN.........................................................................  I-25

                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-13
Item 12         Security Ownership of Certain Beneficial Owners and
                  Management..........................................................................................   III-30
Item 13         Certain Relationships and Related Transactions........................................................   III-35

                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. Other defined
              terms specific only to Item 11 are found on page III-13.

              Term                                                             Meaning

              <S>                                                  <C>
              AEC...........................................       Alabama Electric Cooperative, Inc.
              AFUDC.........................................       Allowance for Funds Used During Construction
              ALABAMA.......................................       Alabama Power Company
              Alicura.......................................       Hidroelectrica Alicura, S.A. (Argentina)
              AMEA..........................................       Alabama Municipal Electric Authority
              APEA..........................................       Applicant Prepared Environmental Assessment
              CEMIG.........................................       Companhia Energetica de Minas Gerais
              CEPA..........................................       Consolidated Electric Power Asia
              Clean Air Act.................................       Clean Air Act Amendments of 1990
              Dalton........................................       City of Dalton, Georgia
              DOE...........................................       United States Department of Energy
              Edelnor.......................................       Empresa Electrica del Norte Grande, S.A. (Chile)
              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
              EWG...........................................       Exempt wholesale generator
              FERC..........................................       Federal Energy Regulatory Commission
              FPC...........................................       Florida Power Corporation
              FP&L..........................................       Florida Power & Light Company
              Freeport......................................       Freeport Power Company (Bahamas)
              FUCO..........................................       Foreign utility company
              GEORGIA.......................................       Georgia Power Company
              GULF..........................................       Gulf Power Company
              Holding Company Act...........................       Public Utility Holding Company Act of 1935, as amended
              IBEW..........................................       International Brotherhood of Electrical Workers
              integrated Southeast utilities................       ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
              IPP...........................................       Independent power producer
              IRS...........................................       Internal Revenue Service
              JEA...........................................       Jacksonville Electric Authority
              MEAG..........................................       Municipal Electric Authority of Georgia
              MISSISSIPPI...................................       Mississippi Power Company
              Mobile Energy.................................       Mobile Energy Services Company, LLC
              NRC...........................................       Nuclear Regulatory Commission
              OPC...........................................       Oglethorpe Power Corporation
              PSC...........................................       Public Service Commission
              RTO...........................................       Regional Transmission Organization
              RUS...........................................       Rural Utility Service (formerly Rural Electrification
                                                                   Administration)



                                       ii
<PAGE>


                                   DEFINITIONS
                                   (continued)



              SAVANNAH......................................       Savannah Electric and Power Company
              SCEM..........................................       Southern Company Energy Marketing, L.P.
              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 Energy...............................       Southern Energy, Inc.
              Southern LINC.................................       Southern Communications Services, Inc.
              Southern Nuclear..............................       Southern Nuclear Operating Company, Inc.
              SOUTHERN system...............................       SOUTHERN, the integrated Southeast utilities, SEGCO,
                                                                   Southern Energy, Southern Nuclear, SCS, Southern LINC, Energy
                                                                   Solutions and other subsidiaries
              TVA...........................................       Tennessee Valley Authority
              WPD...........................................       Western Power Distribution (United Kingdom)
                                                                    (formerly South Western Electricity plc)


                                      iii
</TABLE>

<PAGE>



                         CAUTIONARY STATEMENT REGARDING
                           FORWARD-LOOKING INFORMATION

         This Annual Report on Form 10-K includes forward-looking and historical
information. The registrants caution that there are various important factors
that could cause actual results to differ materially from those indicated in the
forward-looking information; accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the markets of SOUTHERN's subsidiaries; potential business strategies,
including acquisitions or dispositions of assets or businesses, internal
restructuring or other restructuring options, that may be pursued by the
registrants; state and federal rate regulation in the United States; changes in
or application of environmental and other laws and regulations to which SOUTHERN
and its subsidiaries are subject; political, legal and economic conditions and
developments in the United States and in foreign countries in which the
subsidiaries operate; financial market conditions and the results of financing
efforts; changes in commodity prices and interest rates; weather and other
natural phenomena; the performance of projects undertaken by Southern Energy and
other subsidiaries and the success of efforts to invest in and develop new
opportunities; and other factors discussed elsewhere herein and in other reports
filed from time to time by the registrants 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 integrated
Southeast utilities supply electric service in the states of Alabama, Georgia,
Florida, Mississippi and Georgia, respectively. More particular information
relating to each of the integrated Southeast utilities is as follows:

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

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

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

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

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

    SOUTHERN also owns all the outstanding common stock of Southern Energy,
Southern LINC, Southern Nuclear, SCS, Energy Solutions and other direct and
indirect subsidiaries. Southern Energy acquires, develops, builds, owns and
operates power production and delivery facilities and provides a broad range of
energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States. A further
description of Southern Energy's business and organization follows later in this
section under "Southern Energy." Southern LINC provides digital wireless
communications services to SOUTHERN's integrated Southeast utilities and also
markets these services to the public within the Southeast. Southern Nuclear
provides services to ALABAMA and GEORGIA's nuclear plants. Energy Solutions
develops new business opportunities related to energy products and services.

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

    Reference is also made to Note 14 to the financial statements of SOUTHERN in
Item 8 herein for additional information regarding SOUTHERN's segment and
related information.

                                      I-1
<PAGE>


The SOUTHERN System

Integrated Southeast Utilities

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

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

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

    Reference is made to each registrant's "Management's Discussion and Analysis
- Future Earnings Potential" in Item 7 for information relating to the FERC's
final rule issued on December 20, 1999, relating to RTOs.

    SCS has contracted with SOUTHERN, each integrated Southeast utility,
Southern Energy, various of the other subsidiaries, Southern Nuclear and SEGCO
to furnish, at cost and upon request, the following services: general executive
and advisory services, power pool operations, general engineering, design
engineering, purchasing, accounting, finance and treasury, taxes, insurance and
pensions, corporate, rates, budgeting, public relations, employee relations,
systems and procedures and other services with respect to business and
operations. Southern Energy, Energy Solutions and Southern LINC have also
secured from the integrated Southeast utilities certain services which are
furnished at cost.

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

Southern Energy

SOUTHERN continues to consider new business opportunities, particularly those
which allow use of the expertise and resources developed through its regulated
utility experience. These endeavors began in 1981 and are conducted through
Southern Energy and other subsidiaries. Southern Energy is a global company
engaged in electricity generation and distribution, integrated utility
operations and energy marketing. Southern Energy is one of the world's largest
independent power producers with ownership interests in generating facilities
with a total capacity of 28,000 megawatts, of which Southern Energy has net
ownership or control of over 14,000 megawatts. In addition, Southern Energy has
projects under construction or advanced development in which it will have
additional net ownership interests totaling 5,000 megawatts. SOUTHERN has filed
with the SEC a request to invest up to nearly $6 billion in Southern Energy's
domestic and international business. The current SEC authority is $4.1 billion,


                                      I-2
<PAGE>

of which $2.7 billion has been invested as of December 31, 1999. For additional
information relating to Southern Energy's business strategy, reference is made
to Item 7, SOUTHERN's "Management's Discussion and Analysis - Future Earnings
Potential" herein.

    Approximately 60% of the net megawatts of generating capacity currently
owned by Southern Energy is located in the United States, with the remainder in
England, Germany, the Philippines, China, Brazil, Argentina, Chile, the Bahamas
and Trinidad and Tobago. In the United States during 1999, Southern Energy
completed the acquisition of 3,065 megawatts from Pacific Gas & Electric Company
in California and 1,794 megawatts from Orange & Rockland Utilities, Inc. and
Consolidated Edison Company of New York, Inc. in the State of New York. These
North American acquisitions, together with acquisitions completed prior to 1999,
are a component of Southern Energy's strategy of investing in generating assets
which are expected to be linked to Southern Energy's trading and marketing
activities. Also in 1999, Southern Energy completed the acquisition of a 9.99%
ownership interest in Shandong International Power Development Company Limited
which currently owns generating facilities in China with installed capacity of
4,435 megawatts.

    In 1999, Mobile Energy, an indirect subsidiary of SOUTHERN, and its direct
parent filed petitions for Chapter 11 bankruptcy relief in the U.S. Bankruptcy
Court for the Southern District of Alabama. For additional information regarding
this matter, reference is made to Item 3 - LEGAL PROCEEDINGS herein.

    See Item 2 - PROPERTIES - "Other Electric Properties - Southern Energy"
herein for additional information relating to these and other Southern Energy
projects.

    In addition, Southern Energy is a leading energy marketer in North America
through its 60% interest in SCEM, a joint venture between Southern Energy and
Vastar Resources, Inc. formed for the purpose of marketing and trading energy
and energy-linked commodities, including electricity, natural gas, oil, coal and
emission allowances. Southern Energy has also opened an office in Amsterdam, The
Netherlands, in order to market and trade energy in European markets.

    SOUTHERN continues to consider various business strategies and restructuring
options to enhance shareholder value with respect to its investment in Southern
Energy.

Other Business

Energy Solutions is focusing on new and existing programs to enhance customer
satisfaction and efficiency and stockholder value, such as: Good Cents, an
energy efficiency program for electric utility customers; Energy Services,
providing total energy solutions to industrial and commercial customers; Heat
Pump financing for residential customers; and telecommunications operations and
security monitoring for both commercial and residential customers.

     In 1995, Southern LINC began serving SOUTHERN's integrated Southeast
utilities and marketing its services to non-affiliates within the Southeast. Its
system covers approximately 130,000 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 2000-2002 in
these and other new businesses.

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 - "Southern Energy", "Other Business", "Competition" and
"Environmental Regulation." See also "Cautionary Statement Regarding
Forward-Looking Information."

                                      I-3
<PAGE>


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 2000 through
2002 by the integrated Southeast utilities, SEGCO, SCS, Southern LINC and
Southern Energy are estimated as follows: (in millions)

 ------------------------------ -------- --------- ----------
                                   2000      2001      2002
                                -------- --------- ----------
 ALABAMA                     $      831   $743     $    860
 GEORGIA                          1,244     1,511     1,485
 GULF                               106       232        90
 MISSISSIPPI                         84        54        61
 SAVANNAH                            26        30        36
 SEGCO                               15        41        69
 SCS                                 30        24        20
 Southern LINC                       53        27        10
 Southern Energy*                   578     1,044     1,222
 Other                               49       134        88
 =========================== =========== ========= ==========
 SOUTHERN system                 $3,016    $3,840    $3,941
 =========================== =========== ========= ==========

    *These construction estimates do not include amounts which may be expended
by Southern Energy on future power production projects or by any subsidiaries
created to effect such future projects. (See Item 1 - BUSINESS - "Southern
Energy" herein.)


                                      I-4
<PAGE>
<TABLE>
<CAPTION>

Estimated construction costs in 2000 are expected to be apportioned approximately as follows: (in millions)


 ---------------------------- ----------------------- ----------- ------------- ---------- ---------------------------
                              SOUTHERN    Southern
                                system*   Energy      ALABAMA     GEORGIA       GULF       MISSISSIPPI       SAVANNAH
                              ----------------------- ----------- ------------- ---------- ---------------------------
<S>                                 <C>       <C>         <C>         <C>         <C>           <C>         <C>
 New generation                     $641      $  -        $240        $  368      $26           $ 7         $-
 Other generating
    facilities including
    associated plant
    substations                      864       442         140           229       17            16           5
 New business                        372         -         139           176       25            22          10
 Transmission                        420        10         143           225       16            25           1
 Joint line and substation            54         -           -            47        7             -           -
 Distribution                        289       103          89            73        9             7           8
 Nuclear fuel                         93         -          32            61        -             -           -
 General plant                       283        23          48            65        6             7           2
                              ----------------------- ----------- ------------- ---------- ---------------------------
                                  $3,016      $578        $831        $1,244     $106           $84         $26
                              ======================= =========== ============= ========== ===========================
</TABLE>



    *Southern LINC, SCS and other businesses plan capital additions to general
plant in 2000 of $53 million, $30 million and $49 million, respectively, while
SEGCO plans capital additions of $15 million to generating facilities. (See Item
1 - BUSINESS "Southern Energy" and "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.

    The integrated Southeast utilities have approximately 5,200 megawatts of
combustion turbine generating capacity scheduled to be placed in service by
2002. Approximately 1,400 megawatts of this new capacity will be dedicated to
the wholesale market. Southern Energy has approximately 1,000 megawatts of owned
capacity under construction. Significant construction of transmission and
distribution facilities and the upgrading of generating plants will be
continuing for the business in the Southeast. (See Item 2 - PROPERTIES - "Other
Electric Properties - Southern Energy" herein for additional information
relating to facilities under development.)

    In 1991, the Georgia legislature passed legislation which requires GEORGIA
and SAVANNAH each to file an Integrated Resource Plan for approval by the
Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the
construction of new power plants and new purchase power contracts. (See Item 1 -
BUSINESS - "Rate Matters - Integrated Resource Planning" herein.)

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

Year 2000

Reference is made to each registrant's "Management's Discussion and Analysis -
Year 2000 Challenge" in Item 7 herein for information relating to Year 2000
issues.



                                      I-5

<PAGE>


Financing Programs

The amount and timing of additional equity capital to be raised in 2000, as well
as subsequent years, will be contingent on SOUTHERN's investment opportunities.
Equity capital can be provided from any combination of public offerings, private
placements, or SOUTHERN's stock plans. Any portion of the common stock required
during 2000 for SOUTHERN's stock plans that is not provided from the issuance of
new stock will be acquired on the open market in accordance with the terms of
such plans.

    The integrated Southeast utilities plan to obtain the funds required for
construction and other purposes from sources similar to those used in the past,
which were primarily from internal sources. However, the type and timing of any
financings -- if needed -- will depend on market conditions and regulatory
approval. Historically the integrated Southeast utilities have relied on
issuances of first mortgage bonds and preferred stock, in addition to pollution
control revenue bonds issued for their benefit by public authorities, to meet
their long-term external financing requirements. Recently, financings have
consisted of unsecured debt and trust preferred securities.

    In addition, future projects undertaken by subsidiaries of Southern Energy,
as with existing projects, will generally be financed with an appropriate mix of
debt that is non-recourse to SOUTHERN and equity.

    Short-term debt is often utilized as appropriate at SOUTHERN and the
integrated Southeast utilities.

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

                      Amount          Outstanding at
                    Authorized       December 31, 1999
                   --------------    ---------------------
                             (in millions)
  ALABAMA            $  750 (1)           $     97
  GEORGIA             1,700 (2)                636
  GULF                   300(1)                 55
  MISSISSIPPI            350(1)                138
  SAVANNAH                90(2)                 64
  SOUTHERN             2,000(1)              1,075
  ------------------ -------------- -- -------------------

Notes:

    (1) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 2000. No SEC authorization is required for
ALABAMA. GULF, MISSISSIPPI and SOUTHERN have received SEC authorization to issue
from time to time short-term and/or term-loan notes to banks and commercial
paper to dealers in the amounts shown through December 31, 2003, December 31,
2002 and March 31, 2001, 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. At December 31, 1999, GEORGIA
had remaining authority of $376 million expiring December 31, 2000. SAVANNAH
received authority from the Georgia PSC for $70 million expiring December 31,
2000.

    Reference is made to Note 5 to the financial statements for SOUTHERN,
ALABAMA, GULF, MISSISSIPPI and SAVANNAH and Note 9 to the financial statements
for GEORGIA in Item 8 herein for information regarding the registrants' credit
arrangements.

                                      I-6

<PAGE>


Fuel Supply

The integrated Southeast utilities' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1997 through
1999 and the estimates for 2000 are shown below:
                                                   Oil and
 ALABAMA               Coal    Nuclear    Hydro       Gas
                     --------- ---------- --------- ---------
            1997        72%      20%        8%         *%
            1998        72       18         8         2
            1999        72       20         5         3
            2000        69       18         7         6

 GEORGIA
            1997        75       22         2         1
            1998        73       22         3         2
            1999        75       22         1         2
            2000        74       22         3         1

 GULF
            1997       100       **        **         *
            1998        98       **        **         2
            1999        97       **        **         3
            2000        98       **        **         2

 MISSISSIPPI
            1997        85       **        **        15
            1998        80       **        **        20
            1999        81       **        **        19
            2000        81       **        **        19

 SAVANNAH
            1997        87       **        **        13
            1998        76       **        **        24
            1999        78       **        **        22
            2000        89       **        **        11

 SEGCO
            1997       100       **        **         *
            1998       100       **        **         *
            1999       100       **        **         *
            2000       100       **        **         *

 SOUTHERN system***
            1997       77        17         4         2
            1998       76        16         4         4
            1999       78        17         2         3
            2000       76        16         4         4
 ---------- ------- --------- ---------- --------- ---------
    *Less than 0.5%.
  **Not applicable.
***Amounts shown for the SOUTHERN system are weighted averages of the integrated
      Southeast utilities and SEGCO.

    The average costs of fuel in cents per net kilowatt-hour generated for 1997
through 1999 are shown below:

                        1997           1998          1999
                    -------------- ------------- -------------

ALABAMA                 1.49           1.54          1.44

GEORGIA                 1.32           1.36          1.34

GULF                    1.99           1.69          1.60

MISSISSIPPI             1.54           1.62          1.65

SAVANNAH                2.27           2.33          2.20

SEGCO                   1.51           1.53          1.77

SOUTHERN
    System*             1.46           1.48          1.45
------------------- -------------- ------------- -------------
*      Amounts shown for the SOUTHERN system are weighted  averages of the
integrated Southeast utilities and SEGCO.

     See SELECTED FINANCIAL DATA in Item 6 herein for each registrant's source
of energy supply.


                                      I-7

<PAGE>

    As of February 11, 2000, the integrated Southeast utilities had stockpiles
of coal on hand at their respective coal-fired plants which represented an
estimated 25.8 days of recoverable supply for bituminous coal and 54.1 days for
sub-bituminous coal. It is estimated that approximately 66.9 million tons of
coal will be consumed in 2000 by the integrated Southeast utilities (including
those units GEORGIA owns jointly with OPC, MEAG and Dalton and operates for FP&L
and JEA and the units ALABAMA owns jointly with AEC). The integrated Southeast
utilities currently have 38 coal contracts. These contracts cover remaining
terms of up to 12 years. Approximately 26% of 2000 estimated coal requirements
will be purchased in the spot market. Management has set a goal whereby the spot
market should be utilized, absent the transition from coal contract expirations,
for 20 to 30% of the SOUTHERN system's coal supply. Additionally, it has been
determined that the inventory targets will be approximately 32 nameplate days of
recoverable supply for the heavy burn season between June 1 and September 30 and
25 nameplate days for the remaining periods. During 1999, the integrated
Southeast utilities' and SEGCO's average price of coal delivered was
approximately $34.77 per ton.

    In 1999, the weighted average sulfur content of all coal purchased by the
integrated Southeast utilities for use in the coal-fired facilities was 0.83%
sulfur. This sulfur level allowed the integrated Southeast utilities to remain
well below the limits as set forth by Phase I of the Clean Air Act. Phase II
sulfur dioxide and nitrogen oxide limits began in 2000. The integrated Southeast
utilities have secured sufficient quantities of lower sulfur coal to help meet
the more stringent Phase II sulfur requirements in conjunction with the sulfur
dioxide allowances banked in Phase I. As more and more strict environmental
regulations are proposed that impact the utilization of coal, the fuel mix will
be monitored to insure that sufficient quantities of the proper type of coal or
natural gas are in place to remain in compliance with applicable laws and
regulations. See Item 1 BUSINESS - "Regulation - Environmental Regulation"
herein.

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

    The integrated Southeast utilities have renegotiated, bought out or
otherwise terminated various coal supply contracts. For more information on
certain of these transactions, see Note 5 to the financial statements of GULF in
Item 8 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 storage capacity currently is available to permit operation into 2003
at Plant Hatch, into 2017 at Plant Vogtle, and into 2009 and 2013 at Plant
Farley units 1 and 2, respectively. Activities for adding dry cask storage
capacity and for potentially increasing spent fuel pool rack capacity at Plant
Hatch during 2000 are in progress. Planning for additional on-site spent fuel
storage capacity at Plant Farley is also in progress, with the intent to place
additional on-site spent fuel storage capacity in operation as early as 2005. In
addition, through Southern Nuclear, ALABAMA and GEORGIA are members of Private
Fuel Storage, LLC, a joint utility effort to develop a private spent fuel
storage facility for temporary storage of spent nuclear fuel. This facility is
planned to begin operation as early as 2003.

    The Energy Act imposed upon utilities with nuclear plants, including ALABAMA
and GEORGIA, obligations for the decontamination and decommissioning of federal
nuclear fuel enrichment facilities. See Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.

                                      I-8
<PAGE>


Territory Served by the Integrated Southeast Utilities

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

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

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

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

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

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

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

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

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

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


                                      I-9

<PAGE>

    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 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 SOUTHERN's AEC Network Transmission Service
Agreement. The rates for this service to AEC are based on the negotiated
agreement on file with the FERC. See Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein for details of ALABAMA's joint-ownership with AEC of a
portion of Plant Miller.

    MISSISSIPPI has an interchange agreement with SMEPA, a generating and
transmitting cooperative, pursuant to which various services are provided,
including the furnishing of protective capacity by MISSISSIPPI to SMEPA. SMEPA
has a generating capacity of 821,000 kilowatts and a transmission system
estimated to be 1,480 miles in length.

    There are 43 electric cooperative organizations operating in, or in areas
adjoining, territory in the State of Georgia in which GEORGIA provides electric
service at retail or wholesale. Three of these organizations obtain their power
from TVA and one from other sources. Since July 1, 1975, OPC has supplied the
requirements of the remaining 39 of these cooperative organizations from
self-owned generation acquired from GEORGIA and, until September 1991, through
partial requirements purchases from GEORGIA. GEORGIA entered into a power
coordination agreement with OPC pursuant to which, effective in September 1991,
OPC ceased to be a partial requirements wholesale customer of GEORGIA. Instead,
OPC began the purchase of 1,250 megawatts of capacity from GEORGIA through 1999,
subject to reduction or extension by OPC, and may satisfy the balance of its
needs through purchases from others. OPC decreased its purchases of capacity by
250 megawatts each in September 1997, 1998 and 1999. Under the amended 1995
Integrated Resource Plan approved by the Georgia PSC in March 1997, the
resources associated with the decreased purchases by OPC in 1997, 1998 and 1999
will be used to meet the needs of GEORGIA's retail customers through 2004. In
April 1999, a new power supply agreement was implemented between GEORGIA and
OPC. Pursuant to this agreement, OPC will purchase 250 megawatts of steam
capacity through March 2006, 250 megawatts of peaking capacity through August of
2000, and 125 megawatts of peaking capacity from September 2000 through August
2001.

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

    AMEA was organized under an act of the Alabama legislature and is comprised
of 11 municipalities. In 1986, ALABAMA entered into a firm power purchase
contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum
of 100 megawatts) for a period of 15 years commencing September 1, 1986. In
October 1991, ALABAMA entered into a second firm power purchase contract with
AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80
megawatts) for a period of 15 years commencing October 1, 1991. In both
contracts the power is being sold to AMEA for its member municipalities that
previously were served directly by ALABAMA as wholesale customers. Under the
terms of the contracts, ALABAMA received payments from AMEA representing the net
present value of the revenues associated with the respective capacity
entitlements. See Note 7 to ALABAMA's financial statements in Item 8 herein for
further information on these contracts.

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


                                      I-10

<PAGE>

    GULF and MISSISSIPPI provide wholesale requirements for one municipal system
each.

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

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

    The retail service rights of all electric suppliers in the State of Georgia
are regulated by the 1973 State Territorial Electric Service Act. Pursuant to
the provisions of this Act, all areas within existing municipal limits were
assigned to the primary electric supplier therein on March 29, 1973 (451
municipalities, including Atlanta, Columbus, Macon, Augusta, Athens, Rome and
Valdosta, to GEORGIA; 115 to electric cooperatives; and 50 to publicly-owned
systems). Areas outside of such municipal limits were either to be assigned or
to be declared open for customer choice of supplier by action of the Georgia PSC
pursuant to standards set forth in the Act. Consistent with such standards, the
Georgia PSC has assigned substantially all of the land area in the state to a
supplier. Notwithstanding such assignments, the Act provides that any new
customer locating outside of 1973 municipal limits and having a connected load
of at least 900 kilowatts may receive electric service from the supplier of its
choice. (See also Item 1 - BUSINESS - "Competition" herein.)
    Under and subject to the provisions of its franchises and concessions and
the 1973 State Territorial Electric Service Act, SAVANNAH has the full but
nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale,
Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee
Island, Springfield, Thunderbolt, Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been
assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and
Screven Counties by the Georgia PSC. (See also Item 1 - BUSINESS - "Competition"
herein.)

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

Long-Term Power Sales Agreements

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

                                      I-11
<PAGE>


Competition

   The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Act. The Energy Act
allows IPPs to access a utility's transmission network in order to sell
electricity to other utilities. This enhances the incentive for IPPs to build
cogeneration plants for a utility's large industrial and commercial customers,
and sell energy generation to other utilities. Also, electricity sales for
resale rates are being driven down by wholesale transmission access and numerous
potential new energy suppliers, including power marketers and brokers. The
integrated Southeast utilities are aggressively working to maintain and expand
their share of wholesale sales in the Southeastern power markets.

   Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry continues to
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of a company to recover its investments, including the regulatory
assets described in Note 1 to each registrant's respective financial statements,
could have a material adverse effect on such company's financial condition and
results of operations. The integrated Southeast utilities are attempting to
minimize or reduce their cost exposure. Reference is made to Note 3 to the
financial statements for SOUTHERN under "Alabama Power Rate Adjustment
Procedures" and "Georgia Power 1998 Retail Rate Order" for information regarding
these efforts.

    Reference is made to each registrant's "Management's Discussion and Analysis
- Future Earnings Potential" in Item 7 for information relating to the FERC's
final rule issued on December 20, 1999, relating to RTOs.

    Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the integrated Southeast utilities do not remain low-cost
producers and provide quality service, then energy sales could be adversely
affected, and this could significantly erode earnings. Reference is made to each
registrant's "Management's Discussion and Analysis - Future Earnings Potential"
in Item 7 herein for further discussion of competition.

    To adapt to a less regulated, more competitive environment and to enhance
shareholder value, 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 or other restructuring options, disposition
of certain assets or businesses, or some combination thereof. Furthermore,
SOUTHERN may engage in other new business ventures that arise from competitive
and regulatory changes in the utility industry. Pursuit of any of the above
strategies, or any combination thereof, may significantly affect the business
operations and financial condition of SOUTHERN. (See Item 1 BUSINESS - "Southern
Energy" 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.

    ALABAMA currently has cogeneration contracts in effect with twelve
industrial customers. Under the terms of these contracts, ALABAMA purchases
excess generation of such companies. During 1999, ALABAMA purchased
approximately 94 million kilowatt-hours from such companies at a cost of $2.2
million.

                                      I-12

<PAGE>


    GEORGIA currently has contracts in effect with six small power producers
whereby GEORGIA purchases their excess generation. During 1999, GEORGIA
purchased 3.9 million kilowatt-hours from such companies at a cost of $638,000.
In June 1998, GEORGIA entered into a 30-year purchased power agreement for
electricity from a 300-megawatt cogeneration facility. Payments are subject to
reductions for failure to meet minimum capacity output. During 1999, GEORGIA
purchased 705.2 million kilowatt-hours at a cost of $39 million from this
facility. 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 1999, GULF purchased 162 million kilowatt-hours from such
companies for $5.0 million.

     In 1996, MISSISSIPPI entered into agreements to purchase options for summer
peaking power for the years 1997 through 2000. Reference is made to Note 5 to
the financial statements for MISSISSIPPI in Item 8 herein for information
regarding fuel and purchased power commitments.

    SAVANNAH currently has cogeneration contracts in effect with six large
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 1999, SAVANNAH purchased 28 million
kilowatt-hours from such companies at a cost of $2.8 million.

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

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

Regulation

State Commissions

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

Holding Company Act

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

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

Federal Power Act

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

    ALABAMA and GEORGIA are also subject to the provisions of the Federal Power
Act or the earlier Federal Water Power Act applicable to licensees with respect
to their hydroelectric developments. Among the hydroelectric projects subject to
licensing by the FERC are 14 existing ALABAMA generating stations having an

                                      I-13

<PAGE>

aggregate installed capacity of 1,582,725 kilowatts and 18 existing GEORGIA
generating stations having an aggregate installed capacity of 1,074,696
kilowatts.

    GEORGIA received a new, 40-year license for the Flint River Project
effective November 1, 1999. GEORGIA has also started the relicensing process for
the Middle Chattahoochee Project. This project consists of the Goat Rock,
Oliver, and North Highlands facilities.

    GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity
which began commercial operation in 1995. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein and Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information.)

    Licenses for all projects, excluding those discussed above, expire in the
period 2007-2033 in the case of ALABAMA's projects and in the period 2005-2036
in the case of GEORGIA's projects.

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

Atomic Energy Act of 1954

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

    NRC operating licenses currently expire in June 2017 and March 2021 for
Plant Farley units 1 and 2, respectively, in August 2014 and June 2018 for Plant
Hatch units 1 and 2, respectively, and in January 2027 and February 2029 for
Plant Vogtle units 1 and 2, respectively.

    On February 29, 2000, Southern Nuclear, on behalf of GEORGIA, filed a
license renewal application with the NRC for Plant Hatch units 1 and 2. If
approved, the operating license will be extended to August 6, 2034 for Plant
Hatch unit 1 and until June 13, 2038 for Plant Hatch unit 2.

    Reference is made to Notes 1 and 12 to SOUTHERN's, Notes 1 and 12 to
ALABAMA's and Notes 1 and 5 to GEORGIA's financial statements in Item 8 herein
for information on nuclear decommissioning costs and nuclear insurance.
Additionally, Note 3 to GEORGIA's financial statements
contains information regarding nuclear performance standards imposed by the
Georgia PSC that may impact retail rates.

Environmental Regulation

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

    Reference is made to each registrant's "Management's Discussion and
Analysis" in Item 7 herein for a discussion of the Clean Air Act and other
environmental legislation and proceedings, including a pending lawsuit brought
on behalf of the EPA.


                                      I-14

<PAGE>


    The integrated Southeast utilities', SEGCO's and Southern Energy's estimated
capital expenditures for environmental quality control facilities for the years
2000, 2001 and 2002 are as follows: (in millions)

 --------------------- --- ---------- ---------- -----------
                              2000        2001        2002
                           ---------- ---------- -----------
 ALABAMA                   $   28     $   78      $  72
 GEORGIA                      161        268        298
 GULF                           2          2          9
 MISSISSIPPI                    -          -          7
 SAVANNAH                       1          2          2
 SEGCO                          4         31         55
 Southern Energy               29         38         69
 --------------------- --- ---------- ---------- -----------
     Total                   $225       $419       $512
 ===================== === ========== ========== ===========
    *The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)

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

    The integrated Southeast utilities, SEGCO and Southern Energy 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.

International Regulation

Southern Energy's international operations are subject to the jurisdiction of
numerous governmental agencies in the countries in which its projects are
located with respect to environmental and other regulatory matters. Generally,
many of the countries in which Southern Energy conducts and will conduct
business have recently developed or are in the process of developing new
regulatory and legal structures to accommodate private and foreign-owned
businesses. These regulatory and legal structures and their interpretation by
applicable administrative agencies are relatively new and sometimes limited, and
more detailed rules and procedures may be issued in the future. The
interpretation of existing rules can also be expected to evolve over time. In
addition, as Southern Energy acquires additional projects in various countries,
it will be affected by the environmental and other regulatory restrictions of
such countries.

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

Rate Matters

Rate Structure

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

    Residential and other rates contain separate customer charges. Rates for
commercial service are presently of the block type and, for large customers, the
billing demand is generally used to determine capacity and minimum bill charges.
These large customers' rates are generally based upon usage by the customer
including those with special features to encourage off-peak usage. Additionally,
the integrated Southeast utilities are allowed by their respective PSCs to
negotiate the terms and compensation of service to large customers. Such terms
and compensation of service, however, are subject to final PSC approval.
ALABAMA, GEORGIA and SAVANNAH are allowed by state law to recover fuel and net
purchased energy costs through fuel cost recovery provisions which are adjusted
to reflect increases or decreases in such costs. GULF recovers from retail

                                      I-15
<PAGE>

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 above base levels
included in the various rate schedules are billed to such customers under the
fuel and energy adjustment clause. The adjustment factors for MISSISSIPPI's
retail and wholesale rates are generally levelized based on the estimated energy
cost for the year, adjusted for any actual over/under collection from the
previous year. Revenues are adjusted for differences between recoverable fuel
costs and amounts actually recovered in current rates.

Rate Proceedings

Reference is made to Note 3 to each registrant's financial statements in Item 8
herein for a discussion of rate matters. Reference is also made to GULF's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein for a discussion of recent Florida PSC matters.

Integrated Resource Planning

GEORGIA and SAVANNAH must file Integrated Resource Plans for approval by the
Georgia PSC. The plans must specify how GEORGIA and SAVANNAH each intends to
meet the future electrical needs of their customers through a combination of
demand-side and supply-side resources. The Georgia PSC must pre-certify these
new resources. Once certified, all prudently incurred construction costs and
purchased power costs will be recoverable through rates.

    In July 1998, the Georgia PSC approved GEORGIA's and SAVANNAH's 1998
Integrated Resource Plans as filed, with minor modifications. The approved plans
identify resource needs of approximately 800 megawatts to 1,200 megawatts
starting in the summer of 2002. As a result, GEORGIA and SAVANNAH issued a joint
request for proposals for their collective needs of 800 megawatts to 1,200
megawatts for 2002 and 2003. The bids were evaluated against self-build options,
and a Certification Filing for the selected resources was approved by the
Georgia PSC in March 2000. The selected resources for retail needs in Georgia
are: (1) a 7-year purchased power agreement with the West Georgia Generating
Company for 310 megawatts starting in 2002, increasing to 465 megawatts in 2005,
and terminating in May 2009; and (2) a 7 1/2-year purchased power agreement for
two 568 megawatt combined cycle units to be located at Plant Wansley starting in
2002 and terminating at the end of 2009. SAVANNAH has a 7-year purchased power
agreement with GEORGIA for 200 megawatts of the 1,136 megawatt addition at Plant
Wansley starting in 2002 and terminating in 2009. After 2009, this capacity will
be available to the wholesale market.

Environmental Cost Recovery Plans

GULF and MISSISSIPPI both have retail rate mechanisms that provide for recovery
of environmental compliance costs. For a description of these plans, see Note 3
to each of GULF's and MISSISSIPPI's financial statements in Item 8 herein.

                                      I-16
<PAGE>


Employee Relations

The companies of the SOUTHERN system had a total of 32,949 employees on their
payrolls at December 31, 1999.

 -------------------------------- --- -------------------------
                                             Employees
                                                 at
                                         December 31, 1999
                                      -------------------------
 ALABAMA                                          6,792
 GEORGIA                                          8,961
 GULF                                             1,339
 MISSISSIPPI                                      1,328
 SAVANNAH                                           533
 SCS                                              3,572
 Southern Energy*                                 6,680
 Southern Nuclear                                 3,018
 Other                                              726
 -------------------------------- --- -------------------------
 Total                                           32,949
 ================================ === =========================
*Includes 5,282 employees on international payrolls.

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

    ALABAMA has agreements with the IBEW on a three-year contract extending to
August 14, 2001. Upon notice given at least 60 days prior to that date,
negotiations may be initiated with respect to agreement terms to be effective
after such date.

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

    GULF has an agreement with the IBEW on a three-year contract extending to
August 15, 2001.

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

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

    Southern Energy has a labor contract with the United Steel Workers that
extends to January 1, 2004  at its State Line facility in Hammond, Indiana.

    Southern Energy Canal located in Sandwich, Massachusetts, and Southern
Energy Kendall located in Cambridge, Massachusetts, both subsidiaries of
Southern Energy, have contracts with the Utilities Workers' Union of America
which expire on June 1, 2001 and March 1, 2001, respectively. Also, Southern
Energy New York has a contract with the IBEW which expires on June 1, 2000.
Currently, Southern Energy New York is in negotiations with the IBEW.

    Southern Nuclear has agreements with the IBEW on separate three-year
contracts extending to August 15, 2001 for Plant Farley and to June 30, 2002 for
Plants Hatch and Vogtle. Upon notice given at least 60 days prior to these
dates, negotiations may be initiated with respect to agreement terms to be
effective after such dates.

    Southern Nuclear also has an agreement with the United Plant Guard Workers
of America for security officers at Plant Hatch extending to September 30, 2001.
Upon notice given at least 60 days prior to that date, negotiations may be
initiated with respect to agreement terms to be effective after such date.

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


                                      I-17

<PAGE>




Item 2.  PROPERTIES

Electric Properties - The Integrated Southeast Utilities

The integrated Southeast utilities and SEGCO, at December 31, 1999, operated 33
hydroelectric generating stations, 33 fossil fuel generating stations and three
nuclear generating stations. The amounts of capacity owned by each company are
shown in the table below.

 ------------------------- -------------------------------------
                                                  Nameplate
 Generating Station        Location              Capacity (1)
 ------------------------- ------------------- -----------------
                                                 (Kilowatts)
 Fossil Steam
 Gadsden                   Gadsden, AL             120,000
 Gorgas                    Jasper, AL            1,221,250
 Barry                     Mobile, AL            1,525,000
 Chickasaw                 Chickasaw, AL            40,000
 Greene County             Demopolis, AL           300,000 (2)
 Gaston Unit 5             Wilsonville, AL         880,000
 Miller                    Birmingham, AL        2,532,288 (3)
                                                 ---------
 ALABAMA Total                                   6,618,538
                                                 ---------

 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                                 21,700,243
                                                   -----------

 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-18
<PAGE>



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

 SAVANNAH Total                                       241,100
                                                      -------

 Gaston (SEGCO)              Wilsonville, AL           19,680 (7)
                                                    ---------
 Total Combustion Turbines                          3,155,637
                                                    ---------

 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             58,000
 Lewis Smith                 Jasper, AL               157,500
 Bankhead                    Holt, AL                  45,125
 Holt                        Holt, AL                  40,000
                                                   ----------
 ALABAMA Total                                      1,582,725
                                                   ----------

 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                     2,660,461
                                                   ----------

 Total Generating Capacity                         31,196,193
                                                   ==========

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



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-19
<PAGE>


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

    MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which is
leased to Entergy Gulf States. The line, completed in 1984, extends from Plant
Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over
a forty-year period covering all expenses and the amortization of the original
$57 million cost of the line. At December 31, 1999, the unamortized portion of
this cost was $35 million.

    The all-time maximum demand on the integrated Southeast utilities and SEGCO
was 30,578,200 kilowatts and occurred in August 1999. This amount excludes
demand served by capacity retained by MEAG and Dalton and excludes demand
associated with power purchased from OPC and SEPA by its preference customers.
The reserve margin for the integrated Southeast utilities and SEGCO at that time
was 8.5%. 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.)


                                      I-20
<PAGE>

Other Electric Properties - Southern Energy

Through special purpose subsidiaries, SOUTHERN owns interests in or operates
independent power production facilities and foreign utility companies. The
generating capacity of these utilities (or facilities) at December 31, 1999, was
as follows:

<TABLE>
<CAPTION>


                             Facilities in Operation
  ------------------------------------------------------------------------------------------------------------------------
                                                                 Megawatts of Capacity         Percent
  Facility              Location                    Units      Owned        Operated         Ownership         Type
  --------------------  --------------------------- ---------  ------------ ----------------------------------------------


<S>                                                    <C>          <C>          <C>              <C>          <C>
  Alicura               Argentina                      4            551 (1)      1,000            55.14 (1)    Hydro
  BEWAG                 Germany                       15            428              -            26.00        Coal
  BEWAG                 Germany                       14            340              -            26.00        Oil & Gas
  Birchwood             Virginia                       1            111            222            50.00        Coal (2)
  CEPA                  China                          3            634             -             32.00        Coal
  CEPA                  Philippines                    2            641            735            87.22        Coal
  CEPA                  Philippines                    3            189            210            90.10        Oil
  CEPA                  China                         16            443              -             9.99        Coal
  CEPA                  Philippines                    2          1,119          1,218            91.90        Coal
  CEPA                  Philippines                    1            100            100           100.00        Oil
  CEPA                  Philippines                    4             15             15           100.00        Diesel
  CEMIG                 Brazil                        34            194              -             3.60        Hydro
  CEMIG                 Brazil                         2              5              -             3.60        Thermal
  CEMIG                 Brazil                         1              -              -             3.60        Wind
  Edelnor               Chile                          2            281            341            82.34        Coal
  Edelnor               Chile                         37            103            125            82.34        Diesel & Hydro
  Freeport              Grand Bahamas                  8             79            126            62.50        Oil
  Penal                 Trinidad and Tobago            5             92             236           39.00        Gas
  Port of Spain         Trinidad and Tobago            6            120             308           39.00        Gas
  Pt. Lisas             Trinidad and Tobago           10            247             634           39.00        Gas
  State Line            Indiana                        2            490             490          100.00        Coal
  SE California         California                    13          3,065           3,065          100.00        Oil & Gas
  SE New York           New York                      16          1,794           1,794          100.00        Oil, Gas, Coal &
                                                                                                               Hydro
  SE New                Maine and Massachusetts        8          1,245           1,236          100.00        Oil & Gas
  England
  SEI Wichita Falls     Texas                          4             80              80          100.00        Gas
  WPD                   United Kingdom                10             71               -            3.77        Gas
  WPD                   United Kingdom                 8              6              12           49.00        Oil & Gas
  WPD                   United Kingdom                 2              3               -           22.00        Wind
  WPD                   United Kingdom                 2              -               2            -           Oil
  ==============================================================================================================================
  Total Capacity                                                 12,446          11,949
  ==============================================================================================================================
</TABLE>


                                      I-21
<PAGE>


Notes:     (1)  Represents megawatts of capacity under a concession
                agreement expiring in the year 2023. In early 2000, Southern
                Energy announced an agreement to sell Alicura, its
                Argentinean assets, substantially at the adjusted carrying value
                with no material gain or loss expected to be recognized in 2000.
            (2) Cogeneration facility.



<TABLE>
<CAPTION>


                          Facilities Under Construction
  -------------------------------------------------------------------------------------------------------------------------------

                                                               Megawatts of Capacity       -----------------
                                                                                           Percent
  Facility              Location                    Units      Own          Operate        Ownership          Type
  --------------------------------------------------------------------------------------------------------------------------------


<S>                                                    <C>          <C>            <C>         <C>            <C>
  SEI Wisconsin         Wisconsin                      2            306            306         100.00         Gas
  SEI Texas             Texas                          3            550            550         100.00         Gas
  Edelnor               Chile                          1            206            250          82.34         Gas
  --------------------------------------------------------------------------------------------------------------------------------
  Total Capacity                                                  1,062          1,106
  ================================================================================================================================
</TABLE>

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>
 Plant Miller
    Units 1 and 2                  1,320             91.8%         8.2%           -%       -%         -%       -%           -%
 Plant Hatch                       1,796               -             -         50.1     30.0       17.7      2.2            -
 Plant Vogtle                      2,320               -             -         45.7     30.0       22.7      1.6            -
 Plant Scherer
   Units 1 and 2                   1,636               -             -          8.4     60.0       30.2      1.4            -
 Plant Wansley                     1,779               -             -         53.5     30.0       15.1      1.4            -
 Rocky Mountain                      848               -             -         25.4     74.6          -        -            -
 Intercession City, FL               142               -             -         33.3        -          -        -         66.7
 ----------------------------- -------------- -- ---------------- -------- ------------ -------- --------- ------------ --------

</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.

    In December 1988, GEORGIA and OPC entered into a joint ownership agreement
for the Rocky Mountain plant under which GEORGIA agreed to retain its present
investment in the project and OPC agreed to finance, complete and operate the
facility. In 1995, the plant went into commercial operation. GEORGIA's ownership
is 25.4 percent. On January 14, 1998, the Georgia PSC ordered that the Company

                                      I-22
<PAGE>


be allowed approximately $108 million of its $142 million investment in the
plant in rate base as of December 31, 1998. GEORGIA appealed the Georgia PSC's
order. Under the rate order approved by the Georgia PSC on December 18, 1998,
GEORGIA accepted the rate base allowance and, in December 1998, GEORGIA recorded
a charge to earnings of $21 million, after taxes, associated with the write-down
of the plant. Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein for additional information regarding the Rocky
Mountain plant.

    In 1994, GEORGIA and FPC entered into a joint ownership agreement regarding
the Intercession City combustion turbine unit. The unit began commercial
operation in January 1997, and is operated by FPC. GEORGIA owns a one-third
interest in the unit, with use of 100% of the capacity from June through
September. FPC has the capacity the remainder of the year.

Titles to Property

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



                                      I-23

<PAGE>


Item 3.  LEGAL PROCEEDINGS

 (1)   United States of America v. ALABAMA, GEORGIA and SCS (United States
       District Court for the Northern District of Georgia)

       Reference is made to Note 3 in each of the registrant's financial
       statements in Item 8 herein.

(2)    Sullivan v. ALABAMA et al.
       (Circuit Court of Jefferson County, Alabama)

       Reference is made to Note 3 to SOUTHERN's and ALABAMA's financial
       statements in Item 8 herein under the captions "Alabama Power Lake Martin
       Litigation" and "Lake Martin Litigation", respectively.

(3)    GEORGIA has been designated as a potentially responsible party under the
       Comprehensive Environmental Response, Compensation and Liability Act with
       respect to a site in Brunswick, Georgia.

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

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

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



(5)    State of Minas Gerais v. Southern Electric Brasil Participacoes Ltda.
       (Appellate Court of the State of Minas Gerais)

       Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
       herein under the caption "Southern Energy Brazilian Investment".


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

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

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

      None.

                                      I-24
<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, 1999.


A. W. Dahlberg
Chairman, Chief Executive Officer, and Director
Age 59
Elected Director in 1985 and Chairman and Chief Executive Officer effective
March 1995. Also served as President from January 1994 to June 1999.

H. Allen Franklin
President, Chief Operating Officer and Director
Age 55
Elected Director in 1988 and President and Chief Operating Officer effective
June 1999. Previously served as President and Chief Executive Officer of GEORGIA
from January 1994 to June 1999.

S. Marce Fuller
Executive Vice President
Age 39
Elected in 1999. She also has served as President and Chief Executive Officer of
Southern Energy since July 1999. Previously Executive Vice President of Southern
Energy from October 1998 to July 1999; Senior Vice President from May 1996 to
October 1998; and Vice President from February 1994 to May 1996. Also served as
President and Chief Executive Officer of SCEM from February 1998 to November
1999.

Elmer B. Harris
Executive Vice President and Director
Age 60
Elected Director in 1989 and Executive Vice President in 1991.  He also has
served as President and Chief Executive Officer of ALABAMA since 1989.

David M. Ratcliffe
Executive Vice President
Age 51
Elected in 1999. He also has served as President and Chief Executive Officer of
GEORGIA since June 1999. Previously served as Executive Vice President and Chief
Financial Officer of GEORGIA from March 1998 to June 1999; Senior Vice President
of SOUTHERN from March 1995 to March 1998; and as President and Chief Executive
Officer of MISSISSIPPI from 1991 to March 1995.

Stephen A. Wakefield
Senior Vice President and General Counsel
Age 59
Elected in 1997.  Previously, he was a partner at the law firm of Akin, Gump,
Strauss, Hauer & Feld, LLP from July 1991 through August 1997.

W. L. Westbrook
Financial Vice President, Chief Financial Officer and Treasurer
Age 60
Elected in 1986. He also has served as Executive Vice President of SCS since
1986.

C. Alan Martin
Vice President
Age 51
Elected in 1998; served as Chief Marketing Officer for the SOUTHERN system.
Previously Vice President of Human Resources of SOUTHERN from 1995 to February
1998. Effective January 1, 2000; elected Executive Vice President of ALABAMA.

Charles D. McCrary
Vice President
Age 48
Elected in 1998; serves as Chief Production Officer for the SOUTHERN system. He
also serves as Executive Vice President of GEORGIA since May 1998. Previously,
he served as Executive Vice President of ALABAMA from 1994 through April 1998.

W. G. Hairston, III
Age 54
President and Chief Executive Officer of Southern Nuclear since 1993.

     The officers of SOUTHERN were elected for a term running from June 1, 1999
for one year until the next annual meeting of directors or until their
successors are elected and have qualified, except for Ms. Fuller who was elected
October 18, 1999.

                                      I-25

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

           1999
           First Quarter           $29-5/8            $23-1/4
           Second Quarter           29-3/16            22-3/4
           Third Quarter            28                 25
           Fourth Quarter           27-1/8             22-1/16


           1998

           First Quarter           $28-11/16          $23-15/16
           Second Quarter           29                 25-1/16
           Third Quarter            29-13/16           25-1/4
           Fourth Quarter           31-9/16            27-3/16


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


           There is no market for the other registrants' common stock, all of
           which is owned by SOUTHERN. On February 29, 2000, the closing price
           of SOUTHERN's common stock was $22-3/16.

      (b)  Number of SOUTHERN's common stockholders
           at December 31, 1999:
                                   174,179

           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 paid and/or declared by SOUTHERN and the operating
           affiliates to their stockholder(s) for the past two years were as
           follows: (in thousands)

           ------------------- --------- ------------- ----------
           Registrant          Quarter       1999          1998
           ------------------- --------- ------------- ----------

           SOUTHERN            First       $233,879     $232,449
                               Second       233,445      233,623
                               Third        228,690      233,763
                               Fourth       225,470      233,506

           ALABAMA             First         98,000       90,400
                               Second        98,400       90,500
                               Third         99,700       90,800
                               Fourth       103,500       95,400

           GEORGIA             First        133,100      132,100
                               Second       133,700      132,300
                               Third        135,500      132,700
                               Fourth       140,700      139,500

           GULF                First         15,000       14,100
                               Second        15,100       14,100
                               Third         15,300       14,100
                               Fourth        15,900       14,900

           MISSISSIPPI         First         13,800       12,700
                               Second        13,800       12,800
                               Third         14,000       12,800
                               Fourth        14,500       13,400

           SAVANNAH            First          6,200        5,800
                               Second         6,200        5,800
                               Third          6,300        5,800
                               Fourth         6,500        6,100
           ------------------- --------- ------------- ----------


    The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of
1998 and 1999. The dividend paid on SOUTHERN's common stock for the first
quarter of 2000 was 33.5(cent) per share.


    The amount of dividends on their common stock that may be paid by the
subsidiary registrants is restricted in accordance with their first mortgage
bond indenture.  The


                                      II-1
<PAGE>


amounts of earnings retained in the business and the amounts restricted against
the payment of cash dividends on common stock at December 31, 1999, were as
follows:

 -------------------- ------------------ --- --------------
                          Retained            Restricted
                          Earnings              Amount
                      ------------------     --------------
                                  (in millions)
 ALABAMA                  $1,225                $   796
 GEORGIA                   1,778                    897
 GULF                        163                    127
 MISSISSIPPI                 172                    118
 SAVANNAH                    111                     68
 Consolidated              4,232                  2,003
 -------------------- ------------------ --- --------------

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-46 and
II-47.

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-111 and II-112.

GULF.  Reference is made to information under the heading "Selected Financial
and Operating Data," contained herein at pages II-140 and II-141.

MISSISSIPPI.  Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-169 and II-170.

SAVANNAH.  Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-195 and II-196.

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-19.

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-51 through II-58.

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-90.

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-116 through II-123.

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-145 through II-151.

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-174 through II-180.


Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Reference is made to information in SOUTHERN's "Management's Discussion and
Analysis - Derivative Financial Instruments" and to Note 1 to SOUTHERN's
financial statements under the headings "Financial Instruments for Non-Trading
Activities" and "Financial Instruments for Trading Activities" contained herein
on pages II-15 through II-16 and II-31 through II-32, 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-55, II-87, II-120, II-148, and II-177,
respectively.


                                      II-2
<PAGE>
<TABLE>
<CAPTION>

Item 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


INDEX TO 1999 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, 1999, 1998 and 1997..................................     II-20
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997..............................     II-21
Consolidated Balance Sheets at December 31, 1999 and 1998...............................................................     II-22
Consolidated Statements of Capitalization at December 31, 1999 and 1998.................................................     II-24
Consolidated Statements of Common Stockholders' Equity for the Years Ended
   December 31, 1999, 1998 and 1997....................................................................................      II-26
Consolidated Statements of Comprehensive Income for the Years Ended
   December 31, 1999, 1998 and 1997....................................................................................      II-26
Notes to Financial Statements...........................................................................................     II-27

ALABAMA:
Report of Independent Public Accountants  ..............................................................................     II-50
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997...............................................     II-59
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997...........................................     II-60
Balance Sheets at December 31, 1999 and 1998 ...........................................................................     II-61
Statements of Capitalization at December 31, 1999 and 1998 .............................................................     II-63
Statements of Common Stockholder's Equity for the Years Ended
   December 31, 1999, 1998 and 1997.....................................................................................     II-65
Notes to Financial Statements...........................................................................................     II-66

GEORGIA:
Report of Independent Public Accountants................................................................................     II-82
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997...............................................     II-91
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997...........................................     II-92
Balance Sheets at December 31, 1999 and 1998 ...........................................................................     II-93
Statements of Capitalization at December 31, 1999 and 1998 .............................................................     II-95
Statements of Common Stockholder's Equity for the Years Ended
   December 31, 1999, 1998 and 1997.....................................................................................     II-97
Notes to Financial Statements...........................................................................................     II-98

GULF:
Report of Independent Public Accountants................................................................................     II-115
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997...............................................     II-124
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997...........................................     II-125
Balance Sheets at December 31, 1999 and 1998 ...........................................................................     II-126
Statements of Capitalization at December 31, 1999 and 1998 .............................................................     II-128
Statements of Common Stockholder's Equity for the Years Ended
   December 31, 1999, 1998 and 1997.....................................................................................     II-129
Notes to Financial Statements...........................................................................................     II-130

                                      II-3
<PAGE>


                                                                                                                             Page
MISSISSIPPI:
Report of Independent Public Accountants................................................................................     II-144
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997...............................................     II-152
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997...........................................     II-153
Balance Sheets at December 31, 1999 and 1998 ...........................................................................     II-154
Statements of Capitalization at December 31, 1999 and 1998 .............................................................     II-156
Statements of Common Stockholder's Equity for the Years Ended
   December 31, 1999, 1998 and 1997.....................................................................................     II-158
Notes to Financial Statements...........................................................................................     II-159

SAVANNAH:
Report of Independent Public Accountants................................................................................     II-173
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997...............................................     II-181
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997...........................................     II-182
Balance Sheets at December 31, 1999 and 1998 ...........................................................................     II-183
Statements of Capitalization at December 31, 1999 and 1998 .............................................................     II-185
Statements of Common Stockholder's Equity for the Years Ended
   December 31, 1999, 1998 and 1997.....................................................................................     II-186
Notes to Financial Statements...........................................................................................     II-187


</TABLE>

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

None.

                                      II-4
                              THE SOUTHERN COMPANY
                            AND SUBSIDIARY COMPANIES


                               FINANCIAL SECTION

                                      II-5


<PAGE>
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 1999 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 generally accepted
accounting principles appropriate in the circumstances and necessarily include
amounts that are based on the best estimates and judgments of management.
Financial information throughout this annual report is consistent with the
financial statements.

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

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

   The audit committee of the board of directors, composed of five directors who
are not employees, provides a broad overview of management's financial reporting
and control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.

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

   In management's opinion, the 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 generally accepted accounting principles.




/s/A. W. Dahlberg
A. W. Dahlberg
Chairman and Chief Executive Officer

/s/W. L. Westbrook
W. L. Westbrook
Financial Vice President, Chief Financial Officer,
and Treasurer


February 16, 2000




                                        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, 1999 and 1998, 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, 1999. These financial statements are the responsibility of the
company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

   In our opinion, the consolidated financial statements (pages II-20 through
II-45) referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 1999
and 1998, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States.



/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000




                                      II-7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 1999 Annual Report

Results of Operations

Overview of Consolidated Earnings

Southern Company's 1999 earnings of $1.28 billion or $1.86 per share established
a new record high. Higher earnings were primarily driven by strong growth in the
competitive energy supply business outside the southeastern United States. The
traditional business of selling electricity in the Southeast continued to remain
strong. However, reported earnings in both 1999 and 1998 reflected significant
items not related to the normal day-to-day business activities. After excluding
these items, earnings for 1999 were $1.30 billion or $1.90 per share compared
with $1.23 billion or $1.76 per share in 1998.

   Southern Energy, Inc. (Southern Energy) is the Southern Company subsidiary
that owns and manages its international operations and develops and owns its
competitive energy supply business in North America outside the Southeast.
Southern Energy earnings accounted for approximately 26 percent of Southern
Company's reported net income in 1999. Amortization of goodwill related to
Southern Energy investments reduced earnings per share by 5 cents in 1999 and 4
cents in 1998.

   A reconciliation of reported earnings to earnings excluding non-day to day
business items and the related explanations are as follows:

                             Consolidated         Earnings
                              Net Income          Per Share
                             -------------      --------------
                             1999     1998      1999      1998
                             -------------      --------------
                                (in millions)
Earnings as reported       $1,276  $   977     $1.86     $1.40
---------------------------------------------------------------
Gain on asset sale            (78)       -      (.11)        -
Write down of assets:
    South American
      investments               -      200         -       .29
    Rocky Mountain
      plant                     -       21         -       .03
    Mobile Energy              69        -       .10         -
Work force reductions          50       20       .07       .03
Other                         (14)       7      (.02)      .01
---------------------------------------------------------------
Total adjustments              27      248       .04       .36
---------------------------------------------------------------
Earnings as adjusted       $1,303   $1,225     $1.90     $1.76
===============================================================
Amount and
 percent change               $78      6.4%    $0.14       8.0%
---------------------------------------------------------------

   Southern Energy sold the supply business of South Western Electricity in
1999, and the remaining distribution business was renamed Western Power
Distribution. In 1999, Southern Energy recorded an asset impairment related to
Mobile Energy Services -- see Note 3 to the financial statements. Southern
Energy's write down of assets in 1998 related to investments in Argentina and
Chile not meeting financial expectations, which resulted in an announced plan to
sell these assets. In 1998, Georgia Power wrote down its investment in the Rocky
Mountain pumped storage hydroelectric plant as a result of a settlement related
to its 1998 retail rate proceeding. Work force reduction programs began in late
1999 for Bewag, a German utility in which Southern Energy has a 26 percent
ownership interest. Also, the traditional business recorded costs related to
workforce reductions in 1998.

   Discussion of the results of operations are separated between the traditional
business of the integrated Southeast utilities and Southern Energy.

Integrated Southeast Utilities

The five integrated Southeast utilities provide electric service in four states.
These utilities are Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
and Savannah Electric. They comprise Southern Company's principal business
segment with earnings of $1.1 billion in 1999. A condensed income statement for
this business segment is as follows:

                                           Increase (Decrease)
                              Amount         From Prior Year
                              ------       --------------------
                                1999           1999       1998
---------------------------------------------------------------
                                      (in millions)
Operating revenues            $9,125          $(238)      $675
---------------------------------------------------------------
Fuel                           2,328              7        117
Purchased power                  409             13        182
Other operation
  and maintenance              2,430              4        252
Depreciation
  and amortization               961           (328)       134
Taxes other than
  income taxes                   521             13          7
Write down of assets               -            (34)        34
---------------------------------------------------------------
Total operating expenses       6,649           (325)       726
---------------------------------------------------------------
Operating income               2,476             87        (51)
Other income                      (8)           (84)        93
---------------------------------------------------------------
Earnings before
  interest and taxes           2,468              3         42
Interest charges and other       720             41         48
Income taxes                     675            (28)        16
---------------------------------------------------------------
Net income                    $1,073         $  (10)     $ (22)
===============================================================

                                       II-8


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report

Revenues

Operating revenues changed in 1999 and 1998 as a result of the following
factors:
                                             Increase (Decrease)
                                               From Prior Year
                                             ------------------
                                               1999       1998
---------------------------------------------------------------
                                                (in millions)
Retail --
  Growth and price changes                    $ 166       $258
  Rate reductions                              (352)         -
  Weather                                       (86)       178
  Fuel cost recovery and other                   86        189
---------------------------------------------------------------
Total retail                                   (186)       625
---------------------------------------------------------------
Sales for resale --
  Within service area                           (24)        (2)
  Outside service area                          (49)        12
---------------------------------------------------------------
Total sales for resale                          (73)        10
Other operating revenues                         21         40
---------------------------------------------------------------
Operating revenues                            $(238)      $675
===============================================================
Percent change                                 (2.5)%      7.8%
---------------------------------------------------------------

   Retail revenues of $8.1 billion in 1999 declined as a result of a Georgia
Power rate reduction effective January 1999. For additional information, see
Note 3 to the financial statements under "Georgia Power 1998 Retail Rate Order."
Customer growth in the Southeast somewhat offset the rate decrease. In 1998,
retail revenues increased sharply, up 8.2 percent compared with the prior year.
Continued growth in the traditional service area and the positive impact of
weather on energy sales were the predominant factors causing the rise in
revenues in 1998. Under fuel cost recovery provisions, fuel revenues generally
equal fuel expenses -- including the fuel component of purchased energy -- and
do not affect net income.

   Sales for resale revenues within the service area were $350 million in 1999,
down 6.5 percent from the prior year. This sharp decline resulted primarily from
supplying less electricity under contractual agreements with certain wholesale
customers in 1999, and a slight reduction in these revenues is expected in 2000.
Revenues from sales for resale within the service area were $374 million in
1998, down 0.7 percent from the prior year.

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

                                    1999       1998       1997
---------------------------------------------------------------
                                          (in millions)
Capacity                            $174       $196       $203
Energy                               157        152        183
---------------------------------------------------------------
Total                               $331       $348       $386
===============================================================

   Capacity revenues in 1999 and 1998 declined each year as a result of
adjustments and true-ups related to contractual pricing. No significant declines
in capacity are scheduled until the termination of the contracts in 2010.

Energy Sales

The changes in revenues for the traditional business in the Southeast are
influenced heavily by the amount of energy sold each year. Kilowatt-hour sales
for 1999 and the percent change by year were as follows:

                         Amount            Percent Change
  (billions of          -------     ----------------------------
   kilowatt-hours)        1999      1999       1998      1997
----------------------------------------------------------------
Residential               43.4      (0.2)%     10.9%     (2.2)%
Commercial                43.4       4.0         7.2      2.5
Industrial                56.2       1.6         2.1      2.6
Other                      0.9       1.6         3.1     (1.1)
                         -----
Total retail             143.9       1.7         6.2      1.1
Sales for resale --
  Within service area      9.4      (4.1)       (0.4)    (9.6)
  Outside service area    13.0      (0.4)       (5.6)    27.7
                         -----
Total                    166.3       1.2         4.7      2.2
================================================================

   The rate of increase in 1999 total retail energy sales was significantly
lower than in 1998. Although the total number of residential customers served
increased by 61,000 during the year, residential energy sales experienced a
decline as a result of milder weather in 1999. The rate of growth in 1998 retail


                                      II-9

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


energy sales was the highest one-year increase since 1986. Also, residential
energy sales registered the highest annual increase in over two decades as a
result of hotter-than-normal weather. Commercial and industrial sales, both in
1999 and 1998, continued to show slight gains in excess of the national
averages. This reflects the strength of business and economic conditions in
Southern Company's traditional service area in the southeastern United States.
Energy sales to retail customers are projected to increase at an average annual
rate of 2.2 percent during the period 2000 through 2010.

   Sales to customers outside the service area declined by 0.4 percent in 1999
and by 5.6 percent in 1998 when compared with the respective prior year. The
declines in sales were influenced by weather and fluctuations in prices for oil
and natural gas, the primary fuel sources for utilities with which the company
has long-term contracts. When oil and gas prices fall below a certain level,
these customers can generate electricity to meet their requirements more
economically. However, these fluctuations in energy sales under long-term
contracts have minimal effects on earnings because Southern Company is paid for
dedicating specific amounts of its generating capacity to these utilities
outside the service area.

Expenses

Operating expenses of $6.6 billion for 1999 decreased $325 million. This decline
was primarily attributable to $308 million less accelerated depreciation of
plant being recorded in accordance with the 1998 Georgia Power rate order as
referred to earlier. The costs to produce and deliver electricity for the
traditional business in the Southeast for 1999 increased by $68 million to meet
higher energy demands. All other operating and maintenance expenses declined by
$44 million as a result of continued cost control programs.

   In 1998, operating expenses of $7.0 billion increased $726 million compared
with the prior year. The costs to produce and deliver electricity for the
traditional business in 1998 increased by $359 million to meet higher energy
demands. Non-production operation and maintenance expenses increased $192
million in 1998. Accelerated depreciation of certain assets increased $157
million when compared with 1997.

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

                                    1999       1998       1997
----------------------------------------------------------------
Total generation
  (billions of kilowatt-hours)       165        164        160
Sources of generation
  (percent) --
    Coal                              78         77         77
    Nuclear                           17         16         17
    Hydro                              2          4          4
    Oil and gas                        3          3          2
Average cost of fuel per net
  kilowatt-hour generated
    (cents) --                      1.45       1.48       1.46
----------------------------------------------------------------

   Total fuel and purchased power costs of $2.7 billion in 1999 increased only
$20 million while total energy sales increased 2.0 billion kilowatt-hours
compared with the amounts recorded in 1998. Continued efforts to control energy
costs helped lower the average cost of fuel per net kilowatt-hour generated in
1999. In 1998, fuel and purchased power costs increased $299 million as a result
of 7.4 billion more kilowatt-hours being sold than in 1997.

   Total interest charges and other financing costs in 1999 decreased $41
million from amounts reported in the previous year. The decline reflected
additional refinancing of debt in 1999. Alabama Power and Georgia Power -- in
accordance with their respective rate making procedures -- recorded additional
accelerated amortization of premium on reacquired debt of $85 million in 1999,
$33 million in 1998, and no additional amounts in 1997. Interest charges and
other financing costs increased in 1998 as a result of the additional
amortization being recorded.

                                       II-10

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


Southern Energy

Southern Energy's domestic and international operations provided much of
Southern Company's strong financial growth in 1999. A condensed income statement
for Southern Company's other significant business segment is as follows:

                                           Increase (Decrease)
                              Amount         From Prior Year
                              -------      ---------------------
                                1999           1999       1998
----------------------------------------------------------------
                                      (in millions)
Operating revenues            $2,268          $ 365    $(1,934)
----------------------------------------------------------------
Fuel and purchased power         937             38     (1,996)
Other operation
  and maintenance                477            131        (22)
Depreciation
  and amortization               322             88         40
Taxes other than
  income taxes                    89              2         16
Write down of assets              69           (239)       308
----------------------------------------------------------------
Total operating expenses       1,894             20     (1,654)
----------------------------------------------------------------
Operating income                 374            345       (280)
Gain on asset sales              313            272         17
Other income                     433             99        100
----------------------------------------------------------------
Earnings before
  interest and taxes           1,120            716       (163)
Interest charges and other       666            178         97
Income taxes                     126            249       (298)
----------------------------------------------------------------
Net income                    $  328          $ 289    $    38
================================================================

   Southern Energy recorded several significant items not related to the normal
day-to-day business activities in both 1999 and 1998 as discussed earlier.
Excluding these one time items, earnings were $355 million and $239 million in
1999 and 1998, respectively.

   Southern Energy develops and owns competitive energy supply businesses around
the world. Domestic assets include a 60 percent interest in a top ten energy
trading and marketing business. International operations are principally located
in China, Philippines, England, Germany, Netherlands, Brazil, Chile, Argentina,
Bahamas, and Trinidad and Tobago.

   Earnings by major geographical area -- excluding the one time items -- are as
follows:

                                           Increase (Decrease)
                              Amount         From Prior Year
                              ------        --------------------
                                1999           1999       1998
----------------------------------------------------------------
                                      (in millions)
Asia                            $175           $107        $27
Europe                           142              9         62
North America                     81             78         14
South America                      1            (16)         8
Corporate and other              (44)           (62)        16
----------------------------------------------------------------

   Revenues in 1999 increased 19 percent primarily as a result of acquisitions
in North America of some 6,100 megawatts of generating facilities in late 1998
and in 1999. Also, approximately 1,100 megawatts of owned generating capacity in
Asia went into commercial operation in late 1999.

   In 1998, Southern Energy's revenues declined because its energy trading and
marketing operations -- $2.0 billion in 1997 -- were deconsolidated as of
January 1, 1998, when Southern Energy's joint venture with Vastar Resources,
Inc. (Vastar) became effective. Because of Vastar's significant participation
rights in the joint venture, the equity method of accounting is required. This
results in Southern Energy's share of the joint venture's earnings being
reported in other income in 1999 and 1998. Southern Energy's revenues in 1998 of
$1.9 billion increased by $48 million compared with comparable revenues in 1997
that exclude energy trading and marketing. This increase resulted primarily from
operations of assets obtained in domestic acquisitions.

   The decline in 1998 operating expenses corresponds to the decrease in
revenues resulting primarily from the deconsolidation of the energy trading and
marketing operations as discussed earlier. Approximately $2.0 billion of these
expenses were recorded in 1997 purchased power expenses. Operating expenses and
interest charges increased in 1999 as a result of acquisitions and new
facilities being placed into service.



                                      II-11

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


Effects of Inflation

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

Future Earnings Potential

The results of 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 growth of
Southern Energy's operations and the ability of the integrated Southeast
utilities to achieve energy sales growth in a less regulated, more competitive
environment.

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

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

   The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell energy generation
to other utilities. Also, electricity sales for resale rates are being driven
down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. Southern Company's integrated
utilities are aggressively working to maintain and expand their share of
wholesale sales in the southeastern power markets.

   Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry continues to
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of a company to recover its investments, including the regulatory
assets described in Note 1 to the financial statements, could have a material
adverse effect on financial condition and results of operations.

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





                                      II-12

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


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

   On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
the formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including Southern Company, are required
to make a filing by October 15, 2000. The filing must contain either a proposal
for RTO participation or a description of the efforts made to participate in an
RTO, the reasons for non-participation, any obstacles to participation, and any
plans for further work toward participation. The RTOs that are proposed in the
filings should be operational by December 15, 2001. Southern Company is
evaluating this issue and formulating its response. The outcome of this matter
cannot now be determined.

   The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to allow holding companies to form exempt wholesale generators and foreign
utility companies to sell power largely free of regulation under PUHCA. These
entities are able to sell power to affiliates -- under certain restrictions --
and to own and operate power generating facilities in other domestic and
international markets. To take advantage of existing and evolving opportunities,
Southern Energy -- founded in 1981 -- is focused on several key international
and domestic business lines, including energy trading and marketing,
distribution, and stand-alone generation. As the energy marketplace evolves,
Southern Energy continues to position the company as a major competitor. At
December 31, 1999, Southern Energy's total assets were $13.9 billion, and it had
ownership or control of over 14,000 megawatts of generating capacity. It has
another 5,000 megawatts under construction or advanced development.

   In 1999, Southern Energy refined its business strategy to focus on a few key
geographic regions of the world. Its Asian subsidiary will focus primarily on
China, India, and the Philippines, while also pursuing opportunities in more
developed countries such as Australia and Singapore. In Europe, Southern Energy
will concentrate efforts in the countries that make up the North-South corridor
of continental Europe -- Scandinavia, Italy, Switzerland, Germany, the
Netherlands, and select countries in Eastern Europe. In South America, the
company is in the process of exiting Argentina and Chile and is reviewing
whether or not it will pursue additional opportunities in Brazil. In North
America, the company will target its efforts on four U.S. regions -- the
Northeast, the Midwest, Texas/Louisiana, and California/Desert Southwest -- and
also will pursue opportunities in Canada.

   In the United States, Southern Energy plans to acquire, build, or gain access
to some 20,000 megawatts of generating capacity over the next several years in
order to ensure its success in the evolving competitive wholesale energy supply
business. Currently, Southern Energy owns or controls approximately 8,500
megawatts of capacity in the four targeted regions, with an additional 4,100
megawatts under construction or advanced development. All of these assets will
be closely linked with Southern Energy's energy trading and marketing business,
Southern Company Energy Marketing (SCEM).

   In 1998, Southern Energy and Vastar completed the combination of their energy
trading and marketing activities to form a joint venture, SCEM. SCEM has the
rights to market virtually all of Vastar's natural gas production over a period
of 10 years. Southern Energy's current ownership interest in SCEM is 60 percent.
On July 1, 2001, this ownership interest will automatically increase to 75
percent. Southern Energy has the right -- exercisable during fiscal year 2002 --
to acquire an additional 5 percent interest from Vastar for $80 million. Also,
Vastar has the right -- exercisable in the period from December 1, 2002 through
January 2, 2003 -- to sell its remaining interest in SCEM to Southern Energy.
The price will range from $130 million to $210 million depending on the interest
owned by Vastar at that time, plus certain other contractual considerations.




                                       II-13

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


   Southern Company has filed with the Securities and Exchange Commission (SEC)
a request to invest up to nearly $6 billion in Southern Energy's domestic and
international business. The current SEC authority is $4.1 billion, of which $2.7
billion has been invested as of December 31, 1999.

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

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

   The staff of the SEC has questioned certain of the current accounting
practices of the electric utility industry -- including Southern Company's --
regarding the recognition, measurement, and classification in the financial
statements of decommissioning costs for nuclear generating facilities. In
response to these questions, the Financial Accounting Standards Board (FASB) has
decided to review the accounting for liabilities related to the retirement of
long-lived assets, including nuclear decommissioning. If the FASB issues new
accounting rules, the estimated costs of retiring Southern Company's nuclear and
other facilities may be required to be recorded as liabilities in the
Consolidated Balance Sheets. Also, the annual provisions for such costs could
change. Because of the company's current ability to recover asset retirement
costs through rates, these changes would not have a significant adverse effect
on results of operations. See Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning" for additional information.

   The integrated Southeast utilities are subject to the provisions of FASB
Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In
the event that a portion of a company's operations is no longer subject to these
provisions, the company would be required to write off related regulatory assets
and liabilities that are not specifically recoverable, and determine if any
other assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.

New Accounting Standard

The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 2001. This statement
establishes accounting and reporting standards for derivative instruments --
including certain derivative instruments embedded in other contracts -- and for
hedging activities. Southern Company has not yet quantified the impact of
adopting this statement on its financial statements; however, the adoption could
increase volatility in earnings and other comprehensive income.

Year 2000 Challenge

The work undertaken by Southern Company subsidiaries to prepare critical
computer systems and other date sensitive devices to function correctly in the
Year 2000 was successful. There were no material incidents reported and no
disruption of electric service within the service area of the traditional
business. There were no reports of significant events regarding third parties
that impacted revenues or expenses.

   For the traditional business, original projected total costs for Year 2000
readiness were approximately $91 million. Final projected costs are $94 million
of which $3 million is projected to be spent in 2000 and $6 million was billed
to non-affiliated companies. These costs include labor necessary to identify,
test, and renovate affected devices and systems, and costs for reporting
requirements to state and federal agencies. From its inception through December
31, 1999, the Year 2000 program costs, recognized primarily as expense, amounted
to $85 million based on Southern Company's ownership interest.

   Also, Southern Energy experienced no material incidents or disruption of
electric service for its domestic and international operations. In addition to
the traditional business costs, Southern Energy's final costs for Year 2000
readiness were approximately $17 million -- based on their ownership interest.
Southern Energy's original projected costs were $24 million.





                                      II-14

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report

FINANCIAL CONDITION

Overview

Southern Company's financial condition continues to remain strong. In 1999, the
integrated Southeast utilities' earnings were at the high end of their allowed
range of return on equity, and Southern Energy reported strong earnings growth
in 1999. These factors drove the record consolidated net income of $1.3 billion
in 1999. Consolidated net income -- excluding non-recurring charges -- in 1999
increased $78 million compared with the prior year. In January 1999, Southern
Company modified its dividend policy to lower, over time, the previously
targeted payout ratio of approximately 75 percent down to 50 percent. The
quarterly dividend declared in January 2000 continued to be maintained at
33 1/2 cents per share, or $1.34 annually. This action allows more
internally generated funds to be reinvested in the company, which is expected to
increase long-term shareholder value. This policy supports Southern Company's
strategic goal to become the best investment in the electric utility business.

   Gross property additions to utility plant were $2.6 billion in 1999. The
majority of funds needed for gross property additions since 1996 has been
provided from operating activities. Southern Energy acquired $1.3 billion of
generating assets in 1999 and sold the supply system of South Western
Electricity -- Southern Energy owned 49 percent -- for $256 million. The
Consolidated Statements of Cash Flows provide additional details.

Derivative Financial Instruments

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. Generally, company
policy is that derivatives are to be used only for hedging purposes. Derivative
positions are monitored using techniques that include market valuation and
sensitivity analysis.

   The company's market risk exposures relative to interest rate changes and
currency exchange fluctuations, as discussed later, have not changed materially
versus the previous reporting period. In addition, the company is not aware of
any facts or circumstances that would significantly impact such exposures in the
near-term.

   Interest rate swaps are used to hedge underlying debt obligations. These
swaps hedge specific debt issuances and qualify for hedge accounting. The
interest rate differential is reflected as an adjustment to interest expense
over the life of the instruments. Additionally, the company has interest rate
swaps in foreign currencies. These swaps are designated as hedges of the
company's related debt issuance in the same currency.

   If the company sustained a 100 basis point change in interest rates for all
variable rate debt in all currencies, the change would affect annualized
interest expense by approximately $27 million at December 31, 1999. Based on the
company's overall interest rate exposure at December 31, 1999, 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.

   The company has investments in the United Kingdom and Germany. To hedge its
net investment in these countries, the company uses long-term cross-currency
agreements to reduce a substantial portion of its exposure to fluctuations in
the British pound sterling and German Deutschemark. As a result of these swaps,
a 10 percent sustained decline of the British pound sterling and German
Deutschemark versus the U.S. dollar would not materially affect the consolidated
financial statements.

   The company also has investments in various emerging market countries where
the net investments are not hedged, including Argentina, Chile, Trinidad and
Tobago, Bahamas, Philippines, and China. The company relies on either currency
pegs or contractual or regulatory links to the U.S. dollar to mitigate currency
risk attributable to these investments.




                                       II-15

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


   Also, the company has currency exposure related to its investment in
Companhia Energetica de Minas Gerais (CEMIG) which has not been hedged. Revenues
at CEMIG and dividends from CEMIG are denominated in Brazilian reals; however, a
significant portion of debt incurred to finance CEMIG is required to be repaid
in other currencies. The devaluation of the real in January 1999 resulted in a
net reduction in other comprehensive income of $83 million.

   Based on availability and economics, the company also uses currency swaps and
forward agreements to hedge dollar-denominated debt issued by subsidiaries with
a functional currency other than the U.S. dollar. These swaps offset the dollar
cash flows, thereby effectively converting debt to the respective company's
reporting currency. Gains and losses related to qualified hedges of foreign
currency firm commitments are deferred and included in the basis of the
underlying transactions. To the extent that a qualifying hedge is terminated or
ceases to be effective as a hedge, any deferred gains and losses to that point
continue to be deferred and are included in the basis of the underlying
transaction.

   In addition to the non-trading activities, the company is exposed to market
risks through its electricity, natural gas, and energy trading business in North
America and Europe. The North American trading business is primarily conducted
through the company's joint venture relationship with Vastar. While this joint
venture relationship is accounted for under the equity method of accounting,
Southern Company -- through guarantees it has made jointly with Vastar -- is
exposed to market risk. Southern Company and Vastar have agreed to indemnify
each other against losses under such guarantees in proportion to their
respective ownership shares of the joint venture. At December 31, 1999,
outstanding guarantees related to the estimated fair value of net contractual
commitments were approximately $146 million. Based upon the joint venture's
statistical analysis of its credit risk, Southern Company's potential exposure
under these contractual commitments would not materially differ from the
estimated fair value. The joint venture's gross revenues and cost of sales were
$12.0 billion and $11.9 billion for 1999, respectively; and $9.2 billion and
$9.1 billion for 1998, respectively.

   In 1999, Southern Energy created a European trading operation in Amsterdam.
The business provides risk management services associated with the energy
industry to its customers in the European market.

   To estimate and manage the market risk of its trading and marketing
portfolios, the trading businesses employ a daily Value at Risk (VAR)
methodology. VAR is used to describe a probabilistic approach to measuring the
exposure to market risk. VAR models are relatively sophisticated. However, the
quantitative risk information is limited by the parameters established in
creating the model. The instruments being evaluated may have features that may
trigger a potential loss in excess of calculated amounts if the changes in
commodity prices exceed the confidence level of the model used. The calculation
utilizes the standard deviation of seasonally adjusted historical changes in the
value of the market risk sensitive commodity-based financial instruments to
estimate the amount of change (i.e., volatility) in the current value of these
instruments that could occur at a specified confidence level over a specified
holding interval. The parameters used in the calculation include holding
intervals ranging from 5 days to 3 months, depending upon the type of
instrument, the term of the instrument, the liquidity of the underlying market,
and other factors. The models employ a 95 percent confidence level based on
historical price movement. Based on VAR analysis of the overall commodity price
risk exposure of the trading businesses at December 31, 1999, management does
not anticipate a materially adverse effect on the company's consolidated
financial statements as a result of market fluctuations.

   Due to cost-based rate regulations, the integrated Southeast utilities have
limited exposure to market volatility in interest rates, commodity fuel prices,
and prices of electricity. To mitigate residual risks relative to movements in
electricity prices, the companies enter into fixed price contracts for the
purchase and sale of electricity through the wholesale electricity market.
Realized gains and losses are recognized in the income statement as incurred. At
December 31, 1999, exposure from these activities was not material to the
consolidated financial statements.

   For additional information, see Note 1 to the financial statements under
"Financial Instruments for Non-Trading and Trading Activities."

Capital Structure

Southern Company's ratio of common equity to total capitalization -- including
short-term debt -- was 32.7 percent in 1999, compared with 37.4 percent in 1998,
and 38.6 percent in 1997.



                                       II-16


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


   During 1999, the integrated Southeast utilities sold, through public
authorities, $349 million of pollution control revenue bonds. In addition,
capital and preferred securities of $250 million were issued in 1999. The
companies continued to reduce financing costs by retiring higher-cost bonds and
preferred stock. Retirements of bonds, including maturities, totaled $1.2
billion during 1999, $1.7 billion during 1998, and $507 million during 1997. As
a result, the composite interest rate on long-term debt decreased from 6.9
percent at December 31, 1996 to 6.5 percent at December 31, 1999. Retirements of
preferred stock totaled $86 million during 1999, $239 million during 1998, and
$660 million during 1997.

   In April 1999, Southern Company announced the repurchase of up to 50 million
shares of its common stock over a two-year period through open market or
privately negotiated transactions. The program did not establish a target stock
price or timetable for specific repurchases. Under this program, 32.8 million
shares were repurchased through December 31, 1999. Funding for the program was
provided from Southern Company's commercial paper program. At the close of 1999,
the company's common stock market value was 23 1/2 per share, compared with book
value of $13.82 per share. The market-to-book value ratio was 170 percent at the
end of 1999, compared with 207 percent at year-end 1998, and 186 percent at
year-end 1997.

Capital Requirements for Construction

The construction program of Southern Company is budgeted at $3.0 billion for
2000, $3.8 billion for 2001, and $3.9 billion for 2002. 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.

   The integrated Southeast utilities have approximately 5,200 megawatts of
combustion turbine generating capacity scheduled to be placed in service by
2002. Approximately 1,400 megawatts of this new capacity will be dedicated to
the wholesale market. Southern Energy has approximately 1,000 megawatts of owned
capacity under construction. Significant construction of transmission and
distribution facilities and upgrading of generating plants will be continuing
for the traditional business in the Southeast.

Other Capital Requirements

In addition to the funds needed for the construction program, approximately $2.1
billion will be required by the end of 2002 for present improvement fund
requirements and maturities of long-term debt. Also, the subsidiaries will
continue to retire higher-cost debt and preferred stock and replace these
obligations with lower-cost capital if market conditions permit.

Environmental Matters

On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The EPA concurrently issued to the integrated Southeast
utilities a notice of violation related to 10 generating facilities, which
includes the five facilities mentioned previously. In early 2000, the EPA filed
a motion to amend its complaint to add the violations alleged in its notice of
violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as
defendants.  The complaint and notice of violation are similar to those
brought against and issued to several other electric utilities. These complaints
and notices of violation allege that the utilities had failed to secure
necessary permits or install additional pollution equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. Southern Company believes that its integrated
utilities complied with applicable laws and the EPA's regulations and
interpretations in effect at the time the work in question took place. The Clean
Air Act authorizes civil penalties of up to $27,500 per day per violation at
each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

   In November 1990, the Clean Air Act was signed into law. Title IV of the
Clean Air Act -- the acid rain compliance provision of the law -- significantly
affected Southern Company. Specific reductions in sulfur dioxide and nitrogen
oxide emissions from fossil-fired generating plants are required in two phases.



                                     II-17


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


Phase I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of the company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.

   Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $300 million.

   For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. 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 estimated construction expenditures
by approximately $105 million.

   The States of Georgia and Alabama have proposed or drafted rules to address
one-hour ozone non-attainment in the Atlanta and Birmingham areas. Additional
nitrogen oxide emission controls will be required on certain generating plants
by May 1, 2003. It is expected that seven generating plants will be affected in
the Atlanta area and two plants in the Birmingham area. Additional construction
expenditures for compliance with these new rules are currently estimated at
approximately $850 million.

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

   In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision makes the standards significantly
more stringent. In September 1998, the EPA issued the final regional nitrogen
oxide reduction rule to the states for implementation. The final rule affects 22
states, including Alabama and Georgia. The EPA's July 1997 standards and the
September 1998 rule are being challenged in the courts by several states and
industry groups. Implementation of the final state rules for these three
initiatives could require substantial further reductions in nitrogen oxide and
sulfur dioxide emissions from fossil-fired generating facilities and other
industries in these states. Additional compliance costs and capital expenditures
resulting from the implementation of these rules and standards cannot be
determined until the results of legal challenges are known, and the states have
adopted their final rules.

   The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: additional controls for hazardous
air pollutant emissions; control strategies to reduce regional haze; and
hazardous waste disposal requirements. The impact of any new standards will
depend on the development and implementation of applicable regulations.

   Southern Company must comply with other environmental laws and regulations
that cover the handling and disposal of hazardous waste. Under these various
laws and regulations, the subsidiaries could incur substantial costs to clean up
properties. The subsidiaries conduct studies to determine the extent of any
required cleanup costs and have recognized in their respective financial
statements costs to clean up known sites. These costs for Southern Company
amounted to $4 million in 1999, $6 million in 1998, and $4 million in 1997.
Additional sites may require environmental remediation for which the
subsidiaries may be liable for a portion or all required cleanup costs. See Note
3 to the financial statements for information regarding Georgia Power's
potentially responsible party status at a site in Brunswick, Georgia.

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

   Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Southern Company. The impact of new legislation -- if



                                       II-18

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


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 2000 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital can be provided from any combination of
public offerings, private placements, or the company's stock plans.

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

   To meet short-term cash needs and contingencies, Southern Company had at the
beginning of 2000 approximately $466 million of cash and cash equivalents and
$5.7 billion of unused credit arrangements with banks.

Cautionary Statement Regarding Forward-Looking
Information

Southern Company's 1999 Annual Report contains forward-looking and historical
information. The company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information. Accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the markets of the subsidiary companies; potential business strategies --
including acquisitions or dispositions of assets or internal restructuring --
that may be pursued by the company; state and federal rate regulation in the
United States; changes in or application of environmental and other laws and
regulations to which the company and its subsidiaries are subject; political,
legal and economic conditions and developments in the United States and in
foreign countries in which the subsidiaries operate; financial market conditions
and the results of financing efforts; changes in commodity prices and interest
rates; weather and other natural phenomena; the performance of projects
undertaken by Southern Energy and the success of efforts to invest in and
develop new opportunities; and other factors discussed in the reports --
including Form 10-K -- filed from time to time by the company with the SEC.




                                       II-19

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report


-----------------------------------------------------------------------------------------------------------------------------
                                                                                 1999                 1998              1997
-----------------------------------------------------------------------------------------------------------------------------
                                                                                                 (in millions)
<S>                                                                           <C>                 <C>                <C>
Operating Revenues:
Retail sales                                                                  $ 8,086             $  8,272           $ 7,647
Sales for resale                                                                  823                  896               886
Southern Energy revenues                                                        2,268                1,903             3,837
Other revenues                                                                    408                  332               241
-----------------------------------------------------------------------------------------------------------------------------
Total operating revenues                                                       11,585               11,403            12,611
-----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
   Fuel                                                                         2,720                2,371             2,281
   Purchased power                                                                954                1,243             3,033
   Other                                                                        2,199                2,112             1,930
Maintenance                                                                       945                  887               763
Depreciation and amortization                                                   1,307                1,539             1,367
Taxes other than income taxes                                                     612                  599               572
Write down of assets                                                               69                  342                 -
-----------------------------------------------------------------------------------------------------------------------------
Total operating expenses                                                        8,806                9,093             9,946
-----------------------------------------------------------------------------------------------------------------------------
Operating Income                                                                2,779                2,310             2,665
Other Income:
Interest income                                                                   164                  243               152
Gain on asset sales                                                               315                   59                24
Equity in earnings of unconsolidated subsidiaries                                  94                  123                35
Other, net                                                                         94                   (2)                -
-----------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest, Minority Interests, and Income Taxes                  3,446                2,733             2,876
-----------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt                                                        698                  712               678
Interest on notes payable                                                         183                  108               112
Amortization of debt discount, premium, and expense, net                          125                   65                34
Other interest charges                                                             53                   68                49
Minority interests in subsidiaries                                                183                   80                29
Distributions on capital and preferred securities of subsidiaries                 182                  149               120
Preferred dividends of subsidiaries                                                20                   25                43
-----------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                                           1,444                1,207             1,065
-----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                                    2,002                1,526             1,811
Income taxes                                                                      726                  549               839
-----------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income                                                       $ 1,276             $    977          $    972
=============================================================================================================================
Common Stock Data:
  Average number of shares of common stock outstanding (in millions)              685                  697               685
  Basic and diluted earnings per share of common stock                          $1.86                $1.40             $1.42
  Cash dividends paid per share of common stock                                 $1.34                $1.34             $1.30
-----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.

</TABLE>



                                                                  II-20

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------------
                                                                               1999                 1998              1997
---------------------------------------------------------------------------------------------------------------------------
                                                                                              (in millions)
<S>                                                                         <C>                 <C>               <C>
Operating Activities:
Consolidated net income                                                     $ 1,276             $    977          $    972
Adjustments to reconcile consolidated net income
   to net cash provided from operating activities --
      Depreciation and amortization                                           1,522                1,773             1,592
      Deferred income taxes and investment tax credits                          137                  (22)               (5)
      Gain on asset sales                                                      (315)                 (61)              (25)
      Write down of assets                                                       69                  342                 -
      Equity in earnings of unconsolidated subsidiaries                         (94)                (123)              (35)
      Other, net                                                                172                  (76)              (29)
      Changes in certain current assets and liabilities
         excluding effects from acquisitions --
           Receivables, net                                                    (213)                 151              (229)
           Fossil fuel stock                                                    (26)                 (35)               53
           Materials and supplies                                               (50)                 (10)               21
           Accounts payable                                                    (147)                 (17)              138
           Other                                                                392                 (151)              172
---------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                                   2,723                2,748             2,625
---------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                                     (2,560)              (2,005)           (1,859)
Southern Energy business and asset acquisitions, net of cash acquired        (1,800)                (998)           (2,925)
Sales of property                                                               285                  281                32
Other                                                                          (139)                  86               (13)
---------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                       (4,214)              (2,636)           (4,765)
---------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                     2,131                 (353)              509
Proceeds --
   Other long-term debt                                                       2,646                2,973             2,499
   Capital and preferred securities                                             250                  435             1,321
   Preferred stock                                                                -                  200                 -
   Common stock                                                                  24                  234               360
Redemptions --
   First mortgage bonds                                                        (890)              (1,487)             (168)
   Other long-term debt                                                        (957)                (599)             (802)
   Capital and preferred securities                                            (100)                   -                 -
   Preferred stock                                                              (86)                (239)             (660)
   Common stock repurchased                                                    (862)                (125)                -
Payment of common stock dividends                                              (921)                (933)             (889)
Other                                                                          (150)                  53               126
---------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities                        1,085                  159             2,296
---------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                           (406)                 271               156
Cash and Cash Equivalents at Beginning of Year                                  872                  601               445
---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                    $   466             $    872          $    601
===========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
   Interest (net of amount capitalized)                                      $1,011                 $998              $876
   Income taxes                                                                $642                 $839              $823
Southern Energy business and asset acquisitions --
   Fair value of assets acquired                                             $1,832               $1,072            $4,768
   Less cash paid                                                             1,800                  998             2,925
---------------------------------------------------------------------------------------------------------------------------
Liabilities assumed                                                          $   32               $   74            $1,843
===========================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>

                                                                  II-21




<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------
Assets                                                                                     1999                    1998
-----------------------------------------------------------------------------------------------------------------------
                                                                                                     (in millions)
<S>                                                                                    <C>                     <C>
Current Assets:
Cash and cash equivalents                                                               $   466                $    872
Special deposits                                                                             72                      87
Receivables, less accumulated provisions for uncollectible accounts
   of $59 million in 1999 and $113 million in 1998                                        1,652                   1,692
Unrecovered retail fuel clause revenue                                                      244                     105
Fossil fuel stock, at average cost                                                          311                     252
Materials and supplies, at average cost                                                     585                     515
Other                                                                                       199                     183
-----------------------------------------------------------------------------------------------------------------------
Total current assets                                                                      3,529                   3,706
-----------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service                                                                               36,763                  35,169
Less accumulated provision for depreciation                                              14,076                  13,239
-----------------------------------------------------------------------------------------------------------------------
                                                                                         22,687                  21,930
Nuclear fuel, at amortized cost                                                             227                     217
Construction work in progress                                                             1,630                   1,782
-----------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                                     24,544                  23,929
-----------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries                                         1,376                   1,549
Property rights, net of accumulated amortization of
   $227 million in 1999 and $169 million in 1998                                          2,202                   1,185
Goodwill, net of accumulated amortization of
   $164 million in 1999 and $106 million in 1998                                          2,106                   2,125
Other intangibles, net of accumulated amortization of
   $13 million in 1999 and $1 million in 1998                                               447                     154
Nuclear decommissioning trusts, at fair value                                               658                     516
Leveraged leases                                                                            556                     264
Other                                                                                       580                     374
-----------------------------------------------------------------------------------------------------------------------
Total other property and investments                                                      7,925                   6,167
-----------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes                                                    987                   1,036
Prepaid pension costs                                                                       590                     491
Debt expense, being amortized                                                               145                     129
Premium on reacquired debt, being amortized                                                 217                     294
Other                                                                                       459                     439
-----------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                                   2,398                   2,389
-----------------------------------------------------------------------------------------------------------------------
Total Assets                                                                            $38,396                 $36,191
=======================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>



                                                                  II-22
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity                                                       1999                    1998
-----------------------------------------------------------------------------------------------------------------------
                                                                                                   (in millions)

<S>                                                                                   <C>                      <C>
Current Liabilities:
Securities due within one year                                                          $   576                 $ 1,526
Notes payable                                                                             3,915                   1,828
Accounts payable                                                                            895                   1,027
Customer deposits                                                                           133                     125
Taxes accrued --
   Income taxes                                                                             155                      49
   Other                                                                                    264                     299
Interest accrued                                                                            281                     233
Vacation pay accrued                                                                        120                     112
Other                                                                                       794                     542
-----------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                                 7,133                   5,741
-----------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                             11,747                  10,472
-----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes                                                         4,505                   4,481
Deferred credits related to income taxes                                                    640                     715
Accumulated deferred investment tax credits                                                 693                     723
Employee benefits provisions                                                                513                     474
Prepaid capacity revenues                                                                    80                      96
Other                                                                                       460                     609
-----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                              6,891                   7,098
-----------------------------------------------------------------------------------------------------------------------
Minority interests in subsidiaries                                                          725                     535
-----------------------------------------------------------------------------------------------------------------------
Company or subsidiary obligated mandatorily redeemable
   capital and preferred securities (See accompanying statements)                         2,327                   2,179
-----------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock of subsidiaries (See accompanying statements)                    369                     369
-----------------------------------------------------------------------------------------------------------------------
Common stockholders' equity (See accompanying statements)                                 9,204                   9,797
-----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity                                              $38,396                 $36,191
=======================================================================================================================
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, 7, 12, and 13)
-----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these balance sheets.
</TABLE>



                                                                  II-23
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report


-----------------------------------------------------------------------------------------------------------------------------------
                                                                         1999             1998              1999              1998
-----------------------------------------------------------------------------------------------------------------------------------
                                                                             (in millions)                    (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
   Maturity                        Interest Rates
   -------                         -------------
   <S>                            <C>                             <C>                <C>                     <C>             <C>
   1999                            6.13% to 8.67%                     $     -          $   373
   2000                            6.00% to 8.67%                         200              209
   2001                            8.67%                                    -                9
   2002                            8.67%                                    -               10
   2003                            6.13% to 8.67%                         325              635
   2004                            6.60% to 8.67%                          35               45
   2005 through 2009               6.07% to 8.67%                         105              165
   2010 through 2014               8.67%                                    -               80
   2015 through 2019               8.67%                                    -               38
   2020 through 2024               7.30% to 9.00%                         559              764
   2025 through 2026               6.88% to 7.88%                         117              137
-----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                              1,341            2,465
-----------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
   6.13% to 11.00% due 1999-2002                                            -              437
   6.38% to 11.00% due 2000-2002                                          279                -
   5.35% to 9.75% due 2003-2004                                           901              361
   5.49% to 10.50% due 2005                                               760              551
   6.80% to 9.70% due 2006                                                593              582
   5.76% to 10.25% due 2007                                               583              447
   3.07% to 10.56% due 2008-2015                                        1,605              959
   6.38% to 8.12% due 2018-2038                                           801              803
   6.63% to 7.13% due 2039-2048                                         1,029              729
   Adjustable rates (3.81% to 8.63% at 1/1/00)
      due 1999-2007                                                     1,887            1,958
-----------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable                                           8,438            6,827
-----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
   Pollution control revenue bonds --
      Collateralized:
         4.38% to 6.75% due 2000-2026                                     617              954
         Variable rates (3.70% to 4.85% at 1/1/00)
           due 2011-2025                                                  120              639
      Non-collateralized:
         5.25% to 7.25% due 2003-2034                                     263              110
         Variable rates (3.50% to 6.03% at 1/1/00)
           due 2011-2037                                                1,510              880
-----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                              2,510            2,583
-----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations                                              97              135
-----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net                                  (63)             (98)
-----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
   requirement -- $800 million)                                        12,323           11,912
Less amount due within one year    576                                  1,440
-----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year                    11,747           10,472              49.7%             45.9%
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                                                  11-24

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------------------
                                                                         1999             1998              1999              1998
-----------------------------------------------------------------------------------------------------------------------------------
                                                                             (in millions)                    (percent of total)
<S>                                                                       <C>             <C>              <C>               <C>
Company or Subsidiary Obligated Mandatorily
   Redeemable Capital and Preferred Securities:
$25 liquidation value --
   6.85% to 7.00%                                                         435              235
   7.13% to 7.38%                                                         297              297
   7.60% to 7.63%                                                         415              415
   7.75%                                                                  649              649
   8.14% to 9.00%                                                         481              583
   Auction rate (6.42% at 1/1/00)                                          50                -
-----------------------------------------------------------------------------------------------------------------------------------
Total company or subsidiary obligated mandatorily
   redeemable capital and preferred securities (annual
   distribution requirement -- $176 million)                            2,327            2,179               9.8               9.6
-----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
   4.20% to 7.00%                                                          99              135
$25 par or stated value --
   5.20% to 5.83%                                                         200              200
Adjustable and auction rates -- at 1/1/00:
   4.22% to 4.50%                                                          70              120
-----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $19 million)                        369              455
Less amount due within one year                                             -               86
-----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock of subsidiaries
   excluding amount due within one year                                   369              369               1.6               1.6
-----------------------------------------------------------------------------------------------------------------------------------
Common Stockholders' Equity:
Common stock, par value $5 per share --
   Authorized -- 1 billion shares
   Issued -- 1999:  701 million shares
          -- 1998:  700 million shares
   Treasury -- 1999: 35 million shares
            -- 1998:  2 million shares
   Par value                                                            3,503            3,499
   Paid-in capital                                                      2,480            2,463
   Treasury, at cost                                                     (919)             (58)
Retained earnings                                                       4,232            3,878
Accumulated other comprehensive income                                    (92)              15
-----------------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity                                       9,204            9,797              38.9              42.9
-----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                  $23,647          $22,817             100.0%            100.0%
===================================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>



                                                                  II-25
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report




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

<S>                                     <C>             <C>           <C>            <C>           <C>          <C>
Balance at January 1, 1997                $3,385          $2,053         $   -         $3,764      $   14         $9,216
Net income                                     -               -             -            972           -            972
Other comprehensive income                     -               -             -              -          (7)            (7)
Stock issued                                  82             278             -              -           -            360
Cash dividends                                 -               -             -           (889)          -           (889)
Other                                          -               -             -             (5)          -             (5)
-------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997               3,467           2,331             -          3,842           7          9,647
Net income                                     -               -             -            977           -            977
Other comprehensive income                     -               -             -              -           8              8
Stock issued                                  32             132            70              -           -            234
Stock repurchased, at cost                     -               -          (125)             -           -           (125)
Cash dividends                                 -               -             -           (933)          -           (933)
Other                                          -               -            (3)            (8)          -            (11)
-------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998               3,499           2,463           (58)         3,878          15          9,797
Net income                                     -               -             -          1,276           -          1,276
Other comprehensive income                     -               -             -              -        (107)          (107)
Stock issued                                   4              17             1              -           -             22
Stock repurchased, at cost                     -               -          (861)             -           -           (861)
Cash dividends                                 -               -             -           (921)          -           (921)
Other                                          -               -            (1)            (1)          -             (2)
-------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999              $3,503          $2,480         $(919)        $4,232      $  (92)        $9,204
=========================================================================================================================


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------
                                                                          1999                 1998              1997
--------------------------------------------------------------------------------------------------------------------------
                                                                                          (in millions)

Consolidated Net Income                                                 $1,276                 $977              $972
Other comprehensive income:
   Foreign currency translation adjustments                               (165)                  12               (10)
   Less applicable income taxes (benefits)                                 (58)                   4                (3)
--------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income                                       $1,169                 $985              $965
==========================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>

                                                                  II-26


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 1999 Annual Report


1. Summary of Significant Accounting
   Policies

General

Southern Company is the parent company of five integrated Southeast utilities, a
system service company, Southern Communications Services (Southern LINC),
Southern Company Energy Solutions, Southern Energy, Inc. (Southern Energy),
Southern Nuclear Operating Company (Southern Nuclear), and other direct and
indirect subsidiaries. The integrated Southeast utilities -- Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide
electric service in four states. Contracts among the integrated Southeast
utilities -- related to jointly owned generating facilities, interconnecting
transmission lines, and the exchange of electric power --are regulated by the
Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange
Commission (SEC). The system service company provides, at cost, specialized
services to Southern Company and subsidiary companies. Southern LINC provides
digital wireless communications services to the integrated Southeast utilities
and also markets these services to the public within the Southeast. Southern
Company Energy Solutions develops new business opportunities related to energy
products and services. Southern Nuclear provides services to Southern Company's
nuclear power plants. Southern Energy acquires, develops, builds, owns, and
operates power production and delivery facilities and provides a broad range of
energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States.

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

   The consolidated financial statements reflect investments in controlled
subsidiaries on a consolidated basis. The equity method is used for subsidiaries
in which the company has significant influence but does not control. Certain
prior years' data presented in the consolidated financial statements have been
reclassified to conform with the current year presentation.

Regulatory Assets and Liabilities

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

                                           1999           1998
---------------------------------------------------------------
                                             (in millions)
Deferred income tax charges               $ 987         $1,036
Premium on reacquired debt                  217            294
Department of Energy assessments             52             57
Vacation pay                                 87             81
Postretirement benefits                      33             36
Deferred income tax credits                (640)          (715)
Storm damage reserves                       (29)           (24)
Other, net                                  144            162
---------------------------------------------------------------
Total                                     $ 851         $  927
===============================================================

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



                                       II-27


<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


Revenues and Fuel Costs

Revenues are accrued for service rendered but unbilled at the end of each fiscal
period. Fuel costs are expensed as the fuel is used. Electric rates for the
integrated Southeast utilities include provisions to adjust billings for
fluctuations in fuel costs, the energy component of purchased power costs, and
certain other costs. Revenues are adjusted for differences between recoverable
fuel costs and amounts actually recovered in current regulated rates.

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

   Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $137
million in 1999, $133 million in 1998, and $144 million in 1997. Alabama Power
and Georgia Power have contracts with the U.S. Department of Energy (DOE) that
provide for the permanent disposal of spent nuclear fuel. The DOE failed to
begin disposing of spent fuel in January 1998 as required by the contracts, and
the companies are pursuing legal remedies against the government for breach of
contract. Sufficient storage capacity currently is available to permit operation
into 2003 at Plant Hatch, into 2017 at Plant Vogtle, and into 2009 and 2013 at
Plant Farley units 1 and 2, respectively. Activities for adding dry cask storage
capacity and for potentially increasing spent fuel pool rack capacity at Plant
Hatch during 2000 are in progress. Planning for additional on-site spent fuel
storage capacity at Plant Farley is also in progress, with the intent to place
additional on-site spent fuel storage capacity in operation as early as 2005. In
addition, through Southern Nuclear, Alabama Power and Georgia Power are members
of Private Fuel Storage, LLC, a joint utility effort to develop a private spent
fuel storage facility for temporary storage of spent nuclear fuel. This facility
is planned to begin operation as early as the year 2003.

   Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is funded in part by
a special assessment on utilities with nuclear plants. This assessment 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, 1999, under this law to be approximately $28 million and $21
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 3.5 percent in 1999 and
3.4 percent in 1998 and 1997. When property subject to depreciation is retired
or otherwise disposed of in the normal course of business, its cost -- together
with the cost of removal, less salvage -- is charged to the accumulated
provision for depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
Depreciation expense includes an amount for the expected costs of
decommissioning nuclear facilities and removal of other facilities.

   Georgia Power recorded additional depreciation of electric plant amounting to
$314 million in 1998 and $159 million in 1997. Georgia Power did not record any
additional depreciation in 1999. See Note 3 under "Georgia Power 1998 Retail
Rate Order" for additional information.

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



                                       II-28

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


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
of December 31, 1999, 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       1997       1997
Decommissioning periods:
   Beginning year                   2017       2014       2027
   Completion year                  2031       2027       2038
---------------------------------------------------------------
                                        (in millions)
Site study costs:
   Radiated structures              $629       $372       $317
   Non-radiated structures            60         33         44
---------------------------------------------------------------
Total                               $689       $405       $361
===============================================================
                                        (in millions)
Ultimate costs:
   Radiated structures            $1,868       $722    $   922
   Non-radiated structures           178         65        129
---------------------------------------------------------------
Total                             $2,046       $787     $1,051
===============================================================

Significant assumptions:
   Inflation rate                    4.5%       3.6%       3.6%
   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. Rates used in the assumptions were approved by the
respective public service commissions.

   Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 1999 and fund balances were as follows:

                                   Plant      Plant      Plant
                                  Farley      Hatch     Vogtle
---------------------------------------------------------------
                                        (in millions)
Amount expensed in 1999              $18        $17         $9
Accumulated provisions:
   External trust funds,
      at fair value                 $287       $222       $149
   Internal reserves                  40         22         12
---------------------------------------------------------------
Total                               $327       $244       $161
===============================================================

   Alabama Power's decommissioning costs for ratemaking are based on the site
study. Effective January 1, 1999, the Georgia Public Service Commission
(GPSC)increased Georgia Power's annual provision for decommissioning expenses to
$26 million. This amount is based on the NRC generic estimate to decommission
the radioactive portion of the facilities as of 1997. The estimates are $526
million and $438 million for plants Hatch and Vogtle, respectively. The ultimate
costs associated with the 1997 NRC minimum funding requirements are $1.1 billion
and $1.3 billion for plants Hatch and Vogtle, respectively. Alabama Power and
Georgia Power expect their respective state public service commissions to
periodically review and adjust, if necessary, the amounts collected in rates for
the anticipated cost of decommissioning.

Income Taxes

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

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory
disallowances and impairments. Original cost includes: materials; labor; minor
items of property; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the estimated cost of
funds used during construction. The cost of maintenance, repairs, and


                                       II-29

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


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.

Property Rights

Property rights primarily consist of leasehold interests in Southern Energy's
Asian power generation facilities that are developed under build, operate, and
transfer agreements with the government-owned utility. These construction costs
for Southern Energy are initially recorded as construction work in progress, and
-- after completion -- they are recorded as leasehold interests. These costs are
amortized over the period -- ranging from 12 to 29 years -- that the facility is
operated before transfer to the government-owned utility.

Goodwill and Other Intangible Assets

Goodwill, which represents the excess of cost over the fair value of assets of
businesses acquired, is amortized on a straight-line basis over periods from 30
to 40 years. Other intangible assets are amortized on a straight-line basis over
periods from 15 to 30 years.

Leveraged Leases

Southern Energy has several leveraged lease agreements -- ranging from 21 to 30
years -- that primarily relate to international energy generation, distribution,
and transportation assets. The investment income earned from these leveraged
leases is immaterial for all periods presented.

Impairment of Long-Lived Assets and Intangibles

Southern Company evaluates long-lived assets -- including goodwill and
identifiable intangibles -- 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
their 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.

Foreign Currency Translation

Assets and liabilities of Southern Energy's international operations, where the
local currency is the functional currency, have been translated at year-end
exchange rates, and revenues and expenses have been translated using average
exchange rates prevailing during the year. Adjustments resulting from
translation have been recorded in other comprehensive income. The financial
statements of international operations, where the U.S. dollar is the functional
currency, reflect certain transactions denominated in the local currency that
have been remeasured in U.S. dollars. The remeasurement of local currencies into
U.S. dollars creates gains and losses from foreign currency transactions that
are included in consolidated net income. Gains and losses on foreign currency
transactions are not material for all periods presented.

Comprehensive Income

Comprehensive income -- consisting of net income and foreign currency
translation adjustments net of taxes -- is presented in the consolidated
financial statements. The objective of the statement is to report a measure of
all changes in common stock equity of an enterprise that result from
transactions and other economic events of the period other than transactions
with owners.




                                     II-30
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


Financial Instruments for Non-Trading Activities

Non-trading derivative financial instruments are used 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 utilizes interest rate swaps and cross currency interest rate
swaps to minimize borrowing costs by changing the interest rate and currency of
the original borrowing. For qualifying hedges, the interest rate differential is
reflected as an adjustment to interest expense over the life of the swaps.

   Southern Energy's international operations are exposed to the effects of
foreign currency exchange rate fluctuations. To protect against this exposure,
currency swaps are used to hedge the net investment in certain foreign
subsidiaries, which has the effect of converting foreign currency cash inflows
into U.S. dollars at fixed exchange rates. Gains or losses on these currency
swaps, designated as hedges of net investments, are offset against the
translation effects reflected in other comprehensive income. Non-trading hedging
activities are classified in the same category as the item hedged in the
company's cash flow statement.

   Non-trading financial derivative instruments held at December 31, 1999, were
as follows:

                     Year of                      Unrecognized
                    Maturity or      Notional         Gain
Type                Termination        Amount        (Loss)
-------------------------------     --------------------------
                                          (in millions)
Interest rate
   swaps:             2000-2012        $1,910         $(3)
                      2001-2012    (pound)600        $(49)
                      2002-2007         DM691         $(5)
Cross currency
   swaps              2001-2007    (pound)414        $(11)
Cross currency
   swaption                2003         DM435         $11
-----------------------------------------------------------------
(pound) - Denotes British pound sterling.
DM - Denotes Deutschemark.

   The company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the company's exposure to counterparty credit risk. The company is
unaware of any counterparties that will fail to meet their obligations.

   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, 1999                 $12,226        $11,557
   At December 31, 1998                  11,777         11,626
Capital and preferred securities:
   At December 31, 1999                   2,327          2,015
   At December 31, 1998                   2,179          2,288
--------------------------------------------------------------

   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.

Financial Instruments for Trading Activities

During 1999, Southern Energy created an energy trading company in Amsterdam,
which provides risk management services associated with the energy industry to
its customers in the European market. These services are provided primarily
through a variety of exchange-traded energy contracts including forward
contracts, futures contracts, option contracts, and financial swap agreements.
These contractual commitments, which represent risk management assets and
liabilities, are accounted for using the mark-to-market method of accounting.
Accordingly, they are reflected at fair value, net of future delivery costs, in
the Consolidated Balance Sheets.

   Net unrealized gains from risk management services are immaterial at December
31, 1999. The volumetric weighted average maturity of the contractual
commitments was 1.35 years. The net notional amount of the risk management
assets and liabilities at December 31, 1999 was 5.3 billion kilowatt-hours. The
notional amount is indicative only of the volume of activity and not of the
amount exchanged by the parties to the financial instruments. Consequently,




                                       II-31
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


these amounts are not a measure of market risk. The averages for 1999 were based
on month-end balances. The fair value of these assets and liabilities at
December 31, 1999 was $1 million and $5 million, respectively.

   The Amsterdam trading operations involve elements of credit risk. The trading
operation has attempted to mitigate this risk by establishing controls to
determine and monitor the creditworthiness of counterparties. The company
monitors credit risk on both an individual and group counterparty basis.
Accordingly, the company does not anticipate any material impact to its
financial position or results of operations as a result of counterparty
nonperformance.

2. Retirement Benefits

Southern Company has defined benefit, trusteed, pension plans that cover
substantially all employees. In the United States, Southern Company provides
certain medical care and life insurance benefits for retired employees.
Substantially all these employees may become eligible for such benefits when
they retire. The integrated Southeast utilities fund trusts to the extent
required by their respective regulatory commissions. The measurement date for
plan assets and obligations is September 30 for each year.

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
                                           -------------------
                                             1999         1998
--------------------------------------------------------------
                                                (in millions)
Balance at beginning of year               $4,170       $3,701
Service cost                                  111           99
Interest cost                                 265          273
Benefits paid                                (213)        (201)
Actuarial (gain) loss                        (251)         298
--------------------------------------------------------------
Balance at end of year                     $4,082       $4,170
==============================================================

                                               Plan Assets
                                             -----------------
                                             1999         1998
--------------------------------------------------------------
                                                (in millions)
Balance at beginning of year               $5,978       $5,931
Actual return on plan assets                1,008          223
Employer contributions                          -            4
Benefits paid                                (308)        (180)
--------------------------------------------------------------
Balance at end of year                     $6,678       $5,978
==============================================================

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

                                             1999         1998
---------------------------------------------------------------
                                                (in millions)
Funded status                             $ 2,596      $ 1,808
Unrecognized transition obligation            (76)         (89)
Unrecognized prior service cost               149          119
Unrecognized net gain                      (2,079)      (1,347)
---------------------------------------------------------------
Prepaid asset recognized in the
   Consolidated Balance Sheets            $   590      $   491
===============================================================

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

                                    1999      1998      1997
---------------------------------------------------------------
                                          (in millions)
Service cost                       $ 111     $  99      $  94
Interest cost                        265       273        271
Expected return on
   plan assets                      (451)     (425)      (394)
Recognized net gain                  (42)      (47)       (42)
Net amortization                       2        (9)        (9)
---------------------------------------------------------------
Net pension cost (income)          $(115)    $(109)     $ (80)
===============================================================

Postretirement Benefits

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

                                                Accumulated
                                           Benefit Obligations
                                           --------------------
                                             1999         1998
---------------------------------------------------------------
                                                (in millions)
Balance at beginning of year               $1,037       $  935
Service cost                                   21           18
Interest cost                                  69           69
Benefits paid                                 (36)         (35)
Actuarial (gain) loss                         (95)          50
----------------------------------------------------------------
Balance at end of year                     $  996       $1,037
================================================================



                                     II-32
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report

                                               Plan Assets
                                             ------------------
                                             1999         1998
---------------------------------------------------------------
                                                (in millions)
Balance at beginning of year                 $336         $294
Actual return on plan assets                   36            8
Employer contributions                         60           69
Benefits paid                                 (37)         (35)
---------------------------------------------------------------
Balance at end of year                       $395         $336
===============================================================

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

                                             1999         1998
---------------------------------------------------------------
                                                (in millions)
Funded status                               $(601)       $(701)
Unrecognized transition obligation            203          219
Unrecognized prior service cost                 1            -
Unrecognized net loss (gain)                   11          117
Fourth quarter contributions                   25           30
---------------------------------------------------------------
Accrued liability recognized in the
   Consolidated Balance Sheets              $(361)       $(335)
===============================================================

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

                                    1999      1998       1997
--------------------------------------------------------------
                                          (in millions)
Service cost                        $ 21      $ 18       $ 18
Interest cost                         69        69         66
Expected return on
   plan assets                       (26)      (21)       (18)
Recognized net gain                    2         2          3
Net amortization                      15        14         17
--------------------------------------------------------------
Net postretirement cost             $ 81      $ 82       $ 86
==============================================================

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

                                             1999         1998
---------------------------------------------------------------
Discount                                     7.50%        6.75%
Annual salary increase                       5.00         4.25
Long-term return on plan assets              8.50         8.50
---------------------------------------------------------------

   An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1999 as follows:

                                      1 Percent      1 Percent
                                      Increase        Decrease
----------------------------------------------------------------
                                            (in millions)
Benefit obligation                      $73               $(62)
Service and interest costs                6                 (5)
----------------------------------------------------------------

Work Force Reduction Programs

Southern Company has incurred additional costs for work force reduction
programs. The costs related to these programs were $30 million, $32 million, and
$50 million for the years 1999, 1998, and 1997, respectively. In addition,
certain costs of these programs were deferred and are being amortized in
accordance with regulatory treatment.

3. CONTINGENCIES AND REGULATORY
   MATTERS

Alabama Power Lake Martin Litigation

On November 30, 1998, total judgments of nearly $53 million were entered in
favor of five plaintiffs against Alabama Power and two large textile
manufacturers. The plaintiffs alleged that the manufacturers had discharged
certain polluting substances into a stream that empties into Lake Martin, a
hydroelectric reservoir owned by Alabama Power, and that such discharges had
reduced the value of the plaintiffs' residential lots on Lake Martin. Of the
total amount of the judgments, $155 thousand was compensatory damages and the
remainder was punitive damages. The damages were assessed against all three
defendants jointly. Alabama Power has appealed these judgments to the Supreme
Court of Alabama. While Alabama Power believes that these judgments should be
reversed or set aside, the final outcome of this matter cannot now be
determined.

   Additional actions have been filed by other land owners in the same
subdivision on Lake Martin against the same defendants, including Alabama Power.
The plaintiffs assert substantially the same allegations as in the current
proceeding being appealed. The final outcome of these actions cannot now be
determined.


                                       II-33


<PAGE>


NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


Georgia Power Potentially Responsible Party Status

In January 1995, Georgia Power and four other unrelated entities were notified
by the Environmental Protection Agency (EPA) that they have been designated as
potentially responsible parties under the Comprehensive Environmental Response,
Compensation, and Liability Act with respect to a site in Brunswick, Georgia. As
of December 31, 1999, Georgia Power had recorded approximately $5 million in
cumulative expenses associated with the site. This represents Georgia Power's
agreed-upon share of the removal and remedial investigation and feasibility
study costs.

   The final outcome of this matter cannot now be determined. However, based on
the nature and extent of Georgia Power's activities relating to the site,
management believes that the company's portion of any remaining remediation
costs should not be material to the financial statements.

Environmental Litigation

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

   The EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, which includes the five
facilities mentioned previously. In early 2000, the EPA filed a motion to amend
its complaint to add the violations alleged in its notice of violation, and to
add Gulf Power, Mississippi Power, and Savannah Electric as defendants.  The
complaint and notice of violations are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place.

   An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

Mobile Energy Services Petition for Bankruptcy

On January 14, 1999, Mobile Energy Services Company, LLC (MESC) -- an indirect
subsidiary of Southern Company -- filed a petition for Chapter 11 bankruptcy
relief in the U.S. Bankruptcy Court. As a result of the bankruptcy filing, the
investment in MESC was deconsolidated. MESC 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. This action was in
response to Kimberly-Clark Tissue Company's (Kimberly-Clark) announcement in May
1998 of plans to close its pulp mill, effective September 1, 1999. The pulp mill
had historically provided 50 percent of MESC's revenues.

   As a result of settlement discussions with Kimberly-Clark and MESC's
bondholders, Southern Company recorded in September 1999 an after-tax write down
of $69 million, primarily representing Southern Company's investment in MESC. At
December 31, 1999, MESC had total assets of $395 million and senior debt
outstanding of $193 million of first mortgage bonds and $73 million related to
tax-exempt bonds. In connection with MESC's bond financings, Southern Company
provided certain limited guarantees, in lieu of funding debt service and
maintenance reserve accounts with cash. As of December 31, 1999, Southern
Company had paid $38 million pursuant to the guarantees. Southern Company
continues to have guarantees outstanding of certain potential environmental and
other obligations of MESC that represent a maximum contingent liability of $21
million at December 31, 1999.

   MESC, an unofficial committee of its bondholders, and Kimberly-Clark have
reached a tentative agreement to settle disputes arising from the shutdown of
Kimberly-Clark's pulp mill in Mobile, Alabama, and to reconfigure energy
services at the site. MESC has reached a separate agreement with Southern Energy
to develop and operate a 165-megawatt cogeneration facility at the site,
including providing a combustion turbine for such facility. The bankruptcy court
approved both agreements.

                                       II-34

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


   The finalization of the proposed settlement between MESC and Kimberly-Clark
requires further agreements to be negotiated between the parties and certain
other conditions to be met, including having a plan of reorganization for MESC
be approved by the bankruptcy court and become effective by no later than
October 30, 2000. If these conditions, as well as others set out in the
settlement agreement filed with the bankruptcy court, are not met, then the
proposed settlement would no longer be effective. The final outcome of this
matter cannot now be determined.

Southern Energy Brazilian Investment

In September 1999, a Brazilian appellate court granted a temporary injunction
that suspended the effectiveness of a shareholders' agreement for Companhia
Energetica de Minas Gerais (CEMIG). This ruling suspends the shareholders'
agreement -- including Southern Energy's super majority voting rights -- while
the action to determine the validity of the agreement is litigated in the lower
court. Southern Energy intends to pursue its legal rights in this matter and to
have all of its rights restored regarding CEMIG. Southern Energy does not
anticipate that this temporary suspension of the shareholders' agreement will
have a significant effect on its financial condition or results of operation.

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. 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.

   In June 1995, the APSC issued a rate order granting Alabama Power's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.

   In December 1995, the APSC issued an order authorizing Alabama Power to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the company's actual base rate revenues exceed the budgeted revenues. In April
1997, the APSC issued an additional order authorizing Alabama Power to reduce
balance sheet asset items. This order authorizes the reduction of such items up
to an amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by Alabama Power. In 1998,
Alabama Power -- in accordance with the 1995 rate order -- recorded $33 million
of additional amortization of premium on reacquired debt. Alabama Power did not
record any additional amounts in 1999 or 1997.

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

Georgia Power Investment in Rocky Mountain

In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for Georgia
Power to spend funds from approved securities issuances on the plant. In 1988,
Georgia Power and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the plant. The plant went into commercial operation in 1995.

   In June 1996, the GPSC initiated a review of this plant. On January 14, 1998,
the GPSC ordered that Georgia Power be allowed to include approximately $108
million of its $142 million investment in rate base as of December 31, 1998. In
December 1998, Georgia Power recorded a write down of $34 million -- $21 million
after taxes -- on its investment in Rocky Mountain as a result of the GPSC's
1998 retail rate order discussed later. This matter is now concluded.

Georgia Power 1998 Retail Rate Order

As required by the GPSC, Georgia Power filed a general rate case in 1998. On
December 18, 1998, the GPSC approved a new three-year rate order for Georgia
Power. Under the terms of the order, Georgia Power's earnings will continue to
be evaluated against a retail return on common equity range of 10 percent to
12.5 percent. Georgia Power's annual retail rates were decreased by $262 million
effective January 1, 1999, and by an additional $24 million effective January 1,
2000. In addition, the order provided for $85 million annually to be applied to
accelerated amortization or depreciation of assets, and up to an additional $50
million annually in 2000 and 2001 of any earnings above the 12.5 percent return.
In 1999, Georgia Power -- in accordance with the rate order -- recorded $85
million of additional amortization of premium on reacquired debt.


                                       II-35
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


   Two-thirds of any additional earnings above the 12.5 percent return in any
year will be applied to rate reductions and the remaining one-third retained by
Georgia Power. In 1999, Georgia Power's return was above 12.5 percent, and
accordingly, it recorded $79 million as an estimate of revenues to be refunded
to customers in 2000. During the term of the order, 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, 2001. At that time, the GPSC would be expected to determine
whether the rate order should be continued, modified, or discontinued.

4. CONSTRUCTION PROGRAM

Southern Company is engaged in continuous construction programs, currently
estimated to total some $3.0 billion in 2000, $3.8 billion in 2001, and $3.9
billion in 2002. 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, 1999, significant
purchase commitments were outstanding in connection with the construction
program. The integrated Southeast utilities have approximately 5,200 megawatts
of combustion turbine generating capacity scheduled to be placed in service by
2002. Southern Energy has under construction approximately 1,000 megawatts of
owned capacity. In addition, significant construction will continue related to
transmission and distribution facilities and the upgrading of generating plants.

   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.

5. FINANCING AND COMMITMENTS

Financing

The amount and timing of additional equity capital to be raised in 2000 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital may be provided from any combination of
public offerings, private placements, or the company's stock plans.

   The integrated Southeast utilities' construction programs are expected to be
financed primarily from internal sources. Short-term debt is often utilized and
the amounts available are discussed below. The companies may issue additional
long-term debt and preferred securities primarily for debt maturities and for
redeeming higher-cost securities if market conditions permit.

Bank Credit Arrangements

At the beginning of 2000, unused credit arrangements with banks totaled $5.7
billion, of which $3.1 billion expires during 2000, $1.1 billion during 2001 and
2002, and $1.5 billion during 2003 and 2004. The following table outlines the
credit arrangements by company:

                                    Amount of Credit
                          -------------------------------------
                                                  Expires
                                           --------------------
                                                        2001 &
Company                   Total    Unused      2000     beyond
--------                ---------------------------------------
                                     (in millions)
Alabama Power            $  907    $  907    $  517     $  390
Georgia Power             1,252     1,252       752        500
Gulf Power                  103       103       103          -
Mississippi Power           104       104       104          -
Savannah Electric            61        26        26          -
Southern Company          2,000     2,000     1,000      1,000
Southern Energy           3,021     1,256       574        682
Other                        60        51        51          -
--------------------------------------------------------------
Total                    $7,508    $5,699    $3,127     $2,572
==============================================================

   Approximately $2.5 billion of the credit facilities allows for term loans
ranging from one to three years. Most of the agreements include stated borrowing
rates but also allow for competitive bid loans.

   All of the credit arrangements require payment of commitment fees based on
the unused portion of the commitments or the maintenance of compensating
balances with the banks. These balances are not legally restricted from
withdrawal. Of the total $5.7 billion in unused credit, $1.85 billion, $1.0
billion, $800 million, and $780 million are syndicated credit arrangements of
Southern Company, Georgia Power, Southern Energy, and Alabama Power,
respectively. These facilities also require the payment of agent fees.


                                       II-36
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


   A portion of the $5.7 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, 1999, was $674 million.

   In addition, the companies from time to time borrow under uncommitted lines
of credit with banks. Also, Southern Company, Alabama Power, Georgia Power, and
Southern Energy borrow through commercial paper programs that have the liquidity
support of committed bank credit arrangements.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of the generating plants, Southern
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels, and other financial commitments.
Also, Southern Company has entered into various long-term commitments for the
purchase of electricity. Total estimated long-term obligations at December 31,
1999, were as follows:

                                                     Purchased
Year                                    Fuel           Power
-----                                  ------------------------
                                           (in millions)
2000                                  $1,629            $   81
2001                                   1,351                81
2002                                   1,153                97
2003                                   1,012                99
2004                                     872                95
2005 and thereafter                    3,429             1,006
---------------------------------------------------------------
Total commitments                     $9,446            $1,459
===============================================================

Operating Leases

Southern Company has operating lease agreements with various terms and
expiration dates. These expenses totaled $67 million, $56 million, and $36
million for 1999, 1998, and 1997, respectively. At December 31, 1999, estimated
minimum rental commitments for noncancelable operating leases were as follows:

Year                                                    Amounts
----                                                 ------------
                                                     (in millions)
2000                                                         $ 64
2001                                                           83
2002                                                           89
2003                                                           82
2004                                                           82
2005 and thereafter                                           526
------------------------------------------------------------------
Total minimum payments                                       $926
==================================================================

Long-Term Service Agreements

Southern Energy has entered into several long-term service agreements for the
maintenance and repair of its combustion turbine or combined cycle generating
plants. These agreements may be terminated in the event a planned construction
project is canceled. At December 31, 1999, the annual amounts committed are as
follows:

Year                                                 Amounts
----                                             ---------------
                                                  (in millions)
2000                                                      $  3
2001                                                         8
2002                                                        28
2003                                                        51
2004                                                        62
2005 and thereafter                                        591
----------------------------------------------------------------
Total minimum payments                                    $743
================================================================

Energy Trading and Marketing Commitments

In 1998, Southern Energy and Vastar Resources (Vastar) completed the combination
of their energy trading and marketing activities to form a joint venture,
Southern Company Energy Marketing (SCEM). SCEM buys and sells physical and
financial energy commodities and financial instruments and provides
energy-related products and services. SCEM's gross revenues and cost of sales
for 1999 were $12.0 billion and $11.9 billion, respectively.

   Southern Energy's current ownership interest in SCEM is 60 percent. The
equity method of accounting is used because of Vastar's significant



                                       II-37

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


participation rights. On July 1, 2001, this ownership interest will
automatically increase to 75 percent. Southern Energy has the right --
exercisable during fiscal year 2002 -- to acquire an additional 5 percent
interest from Vastar for $80 million. Also, Vastar has the right -- exercisable
in the period from December 1, 2002 through January 2, 2003 -- to sell its
remaining interest in SCEM to Southern Energy. The price will range from $130
million to $210 million depending on the interest owned by Vastar at that time,
plus certain other contractual considerations.

   Southern Company and Vastar have separately made guarantees to certain
counterparties regarding performance of contractual commitments by SCEM.
Southern Company and Vastar have agreed to indemnify each other against losses
under such guarantees in proportion to their respective ownership shares of
SCEM. At December 31, 1999, outstanding guarantees related to the estimated fair
value of net contractual commitments were approximately $146 million. Based upon
SCEM's statistical analysis of its credit risk, Southern Company's potential
exposure under these contractual commitments would not materially differ from
the estimated fair value.

   Southern Energy has guaranteed certain minimum annual cash distributions,
subject to exclusions, payable by SCEM to Vastar. For 1999, this distribution,
after adjustments, was $17 million. These distributions before any adjustments
total $85 million for the period 2000-2002.

Assets Subject to Lien

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

6. 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 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 project and with Florida
Power Corporation (FPC) for a combustion turbine unit at Intercession City,
Florida.

   At December 31, 1999, 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%       $3,297          $1,630
Plant Hatch
   (nuclear)                50.1           857             604
Plant Miller
   (coal)
   Units 1 and 2            91.8           740             297
Plant Scherer
   (coal)
   Units 1 and 2             8.4           112              51
Plant Wansley
   (coal)                   53.5           299             145
Rocky Mountain
   (pumped storage)         25.4           169              66
Intercession City
   (combustion turbine)     33.3            11               *
---------------------------------------------------------------
*Less than $1 million.

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

7. Long-Term Power Sales Agreements

The integrated Southeast utilities 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 -- expiring at various dates



                                       II-38

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


discussed below -- are firm and pertain to capacity related to specific
generating units. Because the energy is generally sold at cost under these
agreements, profitability is primarily affected by revenues from capacity sales.
The capacity revenues amounted to $174 million in 1999, $196 million in 1998,
and $203 million in 1997.

   Unit power from specific generating plants is currently being sold to FP&L,
FPC, JEA, and the city of Tallahassee, Florida. Under these agreements,
approximately 1,600 megawatts of capacity is scheduled to be sold in 2000.
Thereafter, these sales will decline to some 1,500 megawatts and remain at that
approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after
2000 with a minimum of three years notice -- until the expiration of the
contracts in 2010.

8. INCOME TAXES

At December 31, 1999, the tax-related regulatory assets and liabilities were
$987 million and $640 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.

   Details of income tax provisions are as follows:

                                     1999       1998      1997
--------------------------------------------------------------
                                           (in millions)
Total provision for income taxes:
Federal --
   Current                          $ 486      $ 451     $ 547
   Deferred -- current year           186        195       188
            -- reversal of
                 prior years         (145)      (208)     (160)
--------------------------------------------------------------
                                      527        438       575
--------------------------------------------------------------
State --
   Current                             85        106       104
   Deferred -- current year            16         28        15
            -- reversal of
                 prior years          (10)       (31)      (19)
--------------------------------------------------------------
                                       91        103       100
--------------------------------------------------------------
International                         108          8       164
--------------------------------------------------------------
Total                               $ 726      $ 549     $ 839
==============================================================

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

                                                1999      1998
--------------------------------------------------------------
                                                 (in millions)
Deferred tax liabilities:
   Accelerated depreciation                   $3,439    $3,315
   Property basis differences                  1,516     1,667
   Other                                         585       403
--------------------------------------------------------------
Total                                          5,540     5,385
--------------------------------------------------------------
Deferred tax assets:
   Federal effect of state deferred taxes        102       104
   Other property basis differences              221       239
   Deferred costs                                134       132
   Pension and other benefits                     90        79
   Other                                         420       293
---------------------------------------------------------------
Total                                            967       847
---------------------------------------------------------------
Net deferred tax liabilities                   4,573     4,538
Portion included in current assets, net          (68)      (57)
---------------------------------------------------------------
Accumulated deferred income taxes
   in the Consolidated Balance Sheets         $4,505    $4,481
===============================================================

   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 $35 million in 1999, $38 million in 1998, and $30 million in
1997. At December 31, 1999, all investment tax credits available to reduce
federal income taxes payable had been utilized.

   A reconciliation of the federal statutory income tax rate -- which excludes
the effect of minority interests and preferred dividends -- to the effective
income tax rate is as follows:


                                       1999      1998     1997
---------------------------------------------------------------
Federal statutory rate                 35.0%     35.0%    35.0%
State income tax,
   net of federal deduction             2.8       4.1      3.4
Non-deductible book
   depreciation                         1.3       4.1      2.3
Differences in foreign tax rates       (5.1)     (6.4)       -
Windfall profits tax                      -         -      8.0
Difference in prior years'
   deferred and current tax rate       (0.9)     (1.3)    (1.5)
Other                                  (0.2)     (1.8)    (1.9)
---------------------------------------------------------------
Effective income tax rate              32.9%     33.7%    45.3%
===============================================================

   Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis.


                                     II-39


<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report



        The undistributed earnings of foreign subsidiaries aggregated $435
million as of December 31, 1999, and these subsidiaries' earnings are not
subject to U.S. income tax until distributed.  Of the total undistributed
earnings, provisions for U.S. taxes have not been made on $210 million related
to earnings that are intended to be reinvested indefinitely.

9. COMMON STOCK

Stock Repurchase Programs

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. The program did
not establish a target stock price or timetable for specific repurchases. Under
this program, 32.8 million shares have been repurchased through December 31,
1999. Funding for the program was provided from Southern Company's commercial
paper program.

   In July 1998, Southern Company's Board of Directors authorized the company to
make open market purchases of its common stock in an aggregate amount not to
exceed $300 million through March 31, 1999. The purpose of the program was to
provide shares of common stock for the purchase requirements of Southern
Company's various stockholder, employee, and outside director stock purchase
plans. Under the program, 4.4 million shares were repurchased and 2.4 million
shares were reissued.

Shares Reserved

At December 31, 1999, a total of 47 million shares was reserved for issuance
pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside
Directors Stock Plan, and the Performance Stock Plan.

Performance Stock Plan

As of December 31, 1999, 355 current and former employees participated in the
Performance Stock Plan. The maximum number of shares of common stock that may be
issued under the plan may not exceed 40 million. The prices of options granted
to date have been at the fair market value of the shares on the dates of grant.
Options granted to date become exercisable pro rata over a maximum period of
three years from the date of grant. Options outstanding will expire no later
than 10 years after the date of grant, unless terminated earlier by the Southern
Company Board of Directors in accordance with the plan. Stock option activity in
1998 and 1999 for the plan is summarized below:


                                         Shares        Average
                                        Subject   Option Price
                                      To Option      Per Share
--------------------------------------------------------------
Balance at December 31, 1997          5,399,506         $21.15
Options granted                       1,659,519          27.03
Options canceled                        (23,495)         23.18
Options exercised                      (604,238)         20.21
--------------------------------------------------------------
Balance at December 31, 1998          6,431,292          22.77
Options granted                       2,108,818          26.56
Options canceled                        (27,995)         25.54
Options exercised                       (56,708)         19.51
--------------------------------------------------------------
Balance at December 31, 1999          8,455,407         $23.73
==============================================================
Shares reserved for future grants:
  At December 31, 1997               38,241,376
  At December 31, 1998               36,598,001
  At December 31, 1999               34,515,156
--------------------------------------------------------------
Options exercisable:
  At December 31, 1998                2,653,591
  At December 31, 1999                4,525,349
--------------------------------------------------------------

   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.

   The pro forma impact on earnings of fair-value accounting for options granted
-- as required by FASB Statement No. 123, Accounting for Stock-Based
Compensation -- is less than 1 cent per share and is not significant to the
consolidated financial statements.

Earnings Per Share

FASB Statement No. 128, Earnings per Share, simplifies the methodology for
computing both basic and diluted earnings per share. The only difference in the
two methods for computing Southern Company's per share amounts is attributable
to outstanding options under the Performance Stock Plan. The effect of the stock
options was determined using the treasury stock method. Consolidated net income
as reported was not affected. Shares used to compute diluted earnings per share
are as follows:


                                   Average Common Stock Shares
                                ------------------------------
                                1999         1998         1997
--------------------------------------------------------------
                                      (in thousands)
As reported shares           685,163      696,944      685,033
Effect of options                580          739          201
--------------------------------------------------------------
Diluted shares               685,743      697,683      685,234
==============================================================


                                       II-40


<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 1999, consolidated retained earnings included
$3.5 billion of undistributed retained earnings of the subsidiaries. Of this
amount, $2.0 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures.

10. 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, 1999, capital securities of
$950 million and preferred securities of $1.4 billion were outstanding. Southern
Company guarantees the notes related to $950 million of capital securities
issued on its behalf.

11. 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:

                                               1999       1998
--------------------------------------------------------------
                                                (in millions)
Bond improvement fund requirements             $ 14     $   23
Less:
   Portion to be satisfied by certifying
      property additions                          9         14
--------------------------------------------------------------
Cash requirements                                 5          9
First mortgage bond maturities
   and redemptions                              200        868
Other long-term debt maturities                 371        563
--------------------------------------------------------------
Total                                          $576     $1,440
==============================================================

   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 166 2/3 percent of such requirements.

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

   Improvement fund requirements and/or serial maturities through 2004
applicable to other long-term debt are as follows: $371 million in 2000; $501
million in 2001; $1.0 billion in 2002; $435 million in 2003; and $1.46 billion
in 2004.

12. NUCLEAR INSURANCE

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

   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.



                                     II-41

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


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

   NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can be insured against increased costs of replacement power in an
amount up to $3.5 million per week -- starting 12 weeks after the outage -- for
one year and up to $2.8 million per week for the second and third years.

   Under each of the NEIL policies, members are subject to assessments if losses
each year exceed the accumulated funds available to the insurer under that
policy. The current maximum annual assessments for Alabama Power and Georgia
Power under the three NEIL policies would be $19 million and $21 million,
respectively.

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

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

13. ACQUISITIONS AND ASSET SALES

Acquisitions

Southern Energy completed several acquisitions in both 1999 and 1998. In 1999, a
$801 million acquisition of 3,065 megawatts of generating capacity from Pacific
Gas &Electric in northern California was completed. Additionally, Southern
Energy acquired 1,794 megawatts of generating capacity from Orange and Rockland
Utilities Inc. and Consolidated Edison Inc. for $476 million. A 9.9 percent
interest in Shandong International Power Development Company was purchased in
1999 for $107 million.

   Southern Energy paid $537 million in 1998 to Commonwealth Electric for 1,245
megawatts of generating capacity. Also in 1998, Southern Energy acquired a 3.6
percent economic interest in CEMIG -- a Brazilian utility -- for $274 million.

Assets Sold

Southern Energy's significant asset sales in 1999 and 1998 related to its United
Kingdom subsidiary South Western Electricity (SWEB). The supply system of SWEB
was sold in 1999 for $256 million of which Southern Energy owned 49 percent. The
remaining distribution business was renamed Western Power Distribution. In 1998,
Southern Energy sold a 26 percent interest in SWEB for $170 million.

Assets for Sale

In December 1998, Southern Energy designed and implemented a plan to dispose of
its Argentinean and Chilean investments. As a result, Southern Energy recorded
an after-tax write down of approximately $200 million in 1998 to reflect the
difference between the carrying value of these assets and the estimated fair
value of the businesses. Southern Energy estimated the fair value of the
businesses held for sale based upon bids received from prospective buyers, if
available, or the discounted expected future cash flows to be generated by the
assets. The adjusted carrying value of these assets held for disposal at
December 31, 1999 was $92 million. These assets impacted the Consolidated
Statements of Income as follows:

                     Operating      Operating     Consolidated
Year                 Revenues        Income         Net Income
----                 -----------------------------------------
                                   (in millions)
1999                      $171           $23                $2
1998                       180            37                 5
1997                       180            37                 5

   Depreciation expense was suspended beginning January 1999, and the after-tax
amount of depreciation recorded in 1998 was $16 million. Southern Energy has
been actively pursuing and/or negotiating with potential buyers for its assets
in Argentina and Chile. In early 2000, Southern Energy announced an agreement to
sell its Argentinean assets substantially at the adjusted carrying value with no
material gain or loss expected to be recognized in 2000.



                                       II-42

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


14. SEGMENT AND RELATED INFORMATION

Southern Company's principal business segment is the five integrated Southeast
utilities that provide electric service in four states. The other reportable
business segment is Southern Energy, which includes international operations and
the competitive energy supply businesses in North America outside the Southeast.
Intersegment revenues are not material. Financial data for business segments,
products and services, and geographic areas are as follows:

<TABLE>
<CAPTION>

Business Segments

                                  Integrated                   Southern Energy                    All
                                   Southeast    ------------------------------------------      Other    Reconciling
Year                               Utilities     International      Domestic        Total       (Note)  Eliminations  Consolidated
----                              -------------------------------------------------------------------------------------------------
                                                                         (in millions)
1999
----
<S>                                 <C>               <C>           <C>          <C>             <C>       <C>             <C>
Operating revenues                  $  9,125          $1,532        $   736      $  2,268        $ 222     $    (30)       $11,585
Depreciation and amortization            961             261             61           322           24            -          1,307
Interest income                           64              88             86           174           42         (116)           164
Net interest charges                     700             264            219           483          136          (78)         1,241
Income taxes                             675              85             41           126          (62)         (13)           726
Write down of generating assets            -               -             69            69            -            -             69
Net income from equity
   method subsidiaries                     -             100             (6)           94            -            -             94
Segment net income (loss)              1,073             346            (18)          328         (101)         (24)         1,276
Total assets                          25,251           9,370          4,502        13,872          461       (1,188)        38,396
Investments in equity
   method subsidiaries                    11           1,195            171         1,366            -           (1)         1,376
Gross property additions               1,854             447            232           679           27            -          2,560
Increase in goodwill                       -               -             48            48            -            -             48
-----------------------------------------------------------------------------------------------------------------------------------

                                  Integrated                   Southern Energy                     All
                                   Southeast  --------------------------------------------       Other   Reconciling
 Year                              Utilities    International      Domestic         Total        (Note) Eliminations  Consolidated
-----                             -------------------------------------------------------------------------------------------------
                                                                         (in millions)
1998
----
Operating revenues                  $  9,363          $1,766        $   137      $  1,903      $   166    $     (29)       $11,403
Depreciation and amortization          1,289             216             18           234           16            -          1,539
Interest income                          150              86             61           147           57         (111)           243
Net interest charges                     654             318             91           409           97          (58)         1,102
Income taxes                             703            (101)           (22)         (123)         (12)         (19)           549
Write down of generating assets           34             308              -           308            -            -            342
Net income from equity
   method subsidiaries                     2             126             (5)          121            -            -            123
Segment net income (loss)              1,083              23             16            39         (110)         (35)           977
Total assets                          24,420           9,578          2,869        12,447        1,438       (2,114)        36,191
Investments in equity
   method subsidiaries                    10           1,363            176         1,539            -            -          1,549
Gross property additions               1,298             586             63           649           58            -          2,005
Increase in goodwill                       -              30            261           291            -            -            291
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                                                  II-43

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
<TABLE>
<CAPTION>

                                  Integrated                  Southern Energy                    All
                                   Southeast --------------------------------------------       Other     Reconciling
Year                               Utilities     International      Domestic        Total       (Note)   Eliminations Consolidated
----                             --------------------------------------------------------------------------------------------------
                                                                         (in millions)
1997
-----
<S>                                 <C>               <C>            <C>         <C>          <C>         <C>              <C>
Operating revenues                  $  8,688          $1,748         $2,089      $  3,837     $     98    $     (12)       $12,611
Depreciation and amortization          1,156             179             15           194           17            -          1,367
Interest income                           51              96             42           138           21          (58)           152
Net interest charges                     588             289             73           362           84          (41)           993
Income taxes                             687             181             (6)          175          (17)        (154)           691
Windfall profits tax                       -             148              -           148            -            -            148
Net income from equity
   method subsidiaries                     1              41              7            48            -          (14)            35
Segment net income (loss)              1,105              (4)             5             1         (123)         (11)           972
Total assets                          24,796           9,225          1,832        11,057        1,225       (1,823)        35,255
Investments in equity
   method subsidiaries                    10           1,024            134         1,158            -            -          1,168
Gross property additions               1,080             720              1           721           58            -          1,859
Increase in goodwill                       -           1,649              -         1,649            -            -          1,649
-----------------------------------------------------------------------------------------------------------------------------------
(Note) 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 a wireless
communication company and a developmental company for energy products and services. Amounts for Southern Energy exclude interest
expense to parent Southern Company.
</TABLE>

<TABLE>
<CAPTION>

Products and Services

                                                                      Revenues
                 ------------------------------------------------------------------------------------------------------------------
                                  Integrated
                              Southeast Utilities                                           Southern Energy
                 ---------------------------------------------    ----------------------------------------------------------------
                                                                                                Energy
                                                                                              Trading And
Year             Retail        Wholesale     Other      Total    Generation   Distribution     Marketing       Other        Total
----             ------------------------------------------------------------------------------------------------------------------
                                                                          (in millions)
<S>               <C>             <C>        <C>       <C>         <C>           <C>          <C>               <C>         <C>
1999              $8,086          $823       $216      $9,125      $1,222        $   976        $     -         $70         $2,268
1998               8,272           896        195       9,363         578          1,273              -          52          1,903
1997               7,647           886        155       8,688         513          1,282          1,982          60          3,837
-----------------------------------------------------------------------------------------------------------------------------------



Geographic Areas

                                                                            Revenues
                              ----------------------------------------------------------------------------------------------------
                                                                          International
                                                     -------------------------------------------------------------
                                                                                             All
Year                            Domestic             Europe               Asia              Other         Total     Consolidated
----                          ----------------------------------------------------------------------------------------------------
                                                                             (in millions)
1999                            $10,053             $   976               $342              $214         $1,532          $11,585
1998                              9,637               1,273                273               220          1,766           11,403
1997                             10,863               1,282                247               219          1,748           12,611
-----------------------------------------------------------------------------------------------------------------------------------

</TABLE>



                                                                  II-44

<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
<TABLE>
<CAPTION>


                                                                        Long-Lived Assets
                                --------------------------------------------------------------------------------------------------
                                                                          International
                                                     -----------------------------------------------------------------------------
                                                                                             All
Year                            Domestic             Europe             Asia                Other           Total     Consolidated
----                            --------------------------------------------------------------------------------------------------
                                                                           (in millions)
<S>                             <C>                  <C>                <C>                 <C>            <C>             <C>
1999                            $24,266              $2,449             $4,029              $1,725         $8,203          $32,469
1998                             22,005               2,463              3,772               1,856          8,091           30,096
1997                             21,282               2,428              3,628               1,888          7,944           29,226
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


15. Quarterly Financial Information (Unaudited)
<TABLE>
<CAPTION>

Summarized quarterly financial data for 1999 and 1998 are as follows:

                                                                                      Per Common Share
                                                                    -------------------------------------------------------
                         Operating    Operating Consolidated                                              Price Range
Quarter Ended             Revenues       Income   Net Income        Earnings       Dividends          High          Low
--------------           ------------------------------------      --------------------------------------------------------
                                      (in millions)
<S>                       <C>           <C>            <C>           <C>            <C>              <C>           <C>
March 1999                 $2,442        $  485         $224          $0.32          $0.335           29 5/8         23 1/4
June 1999                   2,791           668          314           0.45           0.335           29 3/16        22 3/4
September 1999              3,736         1,109          615           0.90           0.335           28             25
December 1999               2,616           517          123           0.19           0.335           27 1/8         22 1/16

March 1998                 $2,495        $  573         $242          $0.35          $0.335           28 11/16       23 15/16
June 1998                   2,913           648          270           0.39           0.335           29             25 1/16
September 1998              3,457         1,068          517           0.74           0.335           29 13/16       25 1/4
December 1998               2,538            21          (52)         (0.08)          0.335           31 9/16        27 3/16
---------------------------------------------------------------------------------------------------------------------------

Southern Company's business is influenced by seasonal weather conditions.
Earnings for the fourth quarter 1998 declined by $221 million, or 32 cents per share, as a result of write downs in certain
generating assets as discussed in notes 3 and 13.
</TABLE>

                                                                  II-45
<PAGE>
<TABLE>
<CAPTION>
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1995-1999
Southern Company and Subsidiary Companies 1999 Annual Report



                                                                     1999           1998        1997       1996        1995
----------------------------------------------------------------------------------------------------------------------------

<S>                                                               <C>            <C>         <C>        <C>          <C>
Operating Revenues (in millions)                                  $11,595        $11,403     $12,611    $10,358      $9,180
Consolidated Net Income (in millions)                              $1,276           $977        $972     $1,127      $1,103
Basic and Diluted Earnings Per Share of Common Stock                $1.86          $1.40       $1.42      $1.68      $1.66
Cash Dividends Paid Per Share of Common Stock                       $1.34          $1.34       $1.30      $1.26      $1.22
Return on Average Common Equity (percent)                           13.43          10.04       10.30      12.53      13.01
Total Assets (in millions)                                        $38,396        $36,191     $35,255    $30,230     $30,522
Gross Property Additions (in millions)                             $2,560         $2,005      $1,859     $1,229      $1,401
Southern Energy Business and Asset Acquisitions                    $1,800           $998      $2,925         $-      $1,416
----------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity                                               $ 9,204       $  9,797    $  9,647   $  9,216    $  8,772
Preferred stock and securities                                      2,696          2,548       2,237      1,402       1,432
Long-term debt                                                     11,747         10,472      10,274      7,938       8,274
----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year                       $23,647        $22,817     $22,158    $18,556     $18,478
============================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                                  38.9           42.9        43.5       49.7        47.5
Preferred stock and securities                                       11.4           11.2        10.1        7.6         7.7
Long-term debt                                                       49.7           45.9        46.4       42.7        44.8
----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year                         100.0          100.0       100.0      100.0       100.0
============================================================================================================================
Other Common Stock Data:
Book value per share (year-end)                                    $13.82         $14.04      $13.91     $13.61      $13.10
Market price per share:
   High                                                                29 5/8         31 9/16     26 1/4     25 7/8       25
   Low                                                                 22 1/16        23 15/16    19 7/8     21 1/8       19 3/8
   Close                                                               23 1/2         29 1/16     25 7/8     22 5/8       24 5/8
Market-to-book ratio (year-end) (percent)                           170.0          207.0       186.0      166.2       188.0
Price-earnings ratio (year-end) (times)                              12.6           20.8        18.2       13.5        14.8
Dividends paid (in millions)                                         $921           $933        $889       $846        $811
Dividend yield (year-end) (percent)                                   5.7            4.6         5.0        5.6         5.0
Dividend payout ratio (percent)                                      72.2           95.6        91.5       75.1        73.5
Shares outstanding (in thousands):
   Average                                                        685,163        696,944     685,033    672,590     665,064
   Year-end                                                       665,796        697,747     693,423    677,036     669,543
Stockholders of record (year-end)                                 174,179        187,053     200,508    215,246     225,739
-----------------------------------------------------------------------------------------------------------------------------
Customers for Integrated Southeast Utilities
 (year-end) (in thousands):
Residential                                                         3,339          3,277       3,220      3,157       3,100
Commercial                                                            513            497         479        464         450
Industrial                                                             15             15          16         17          17
Other                                                                   4              5           5          5           5
-----------------------------------------------------------------------------------------------------------------------------
Total                                                               3,871          3,794       3,720      3,643       3,572
=============================================================================================================================
Employees (year-end):
Traditional business                                               26,269         25,206      24,682     25,034      26,452
Southern Energy                                                     6,680          6,642       5,620      3,743       5,430
-----------------------------------------------------------------------------------------------------------------------------
Total                                                              32,949         31,848      30,302     28,777      31,882
=============================================================================================================================
</TABLE>



                                                                  II-46

<PAGE>
<TABLE>
<CAPTION>
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Southern Company and Subsidiary Companies 1999 Annual Report


                                                                     1999           1998        1997       1996        1995
----------------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>            <C>         <C>        <C>           <C>
Operating Revenues (in millions):
Residential                                                      $  3,105       $  3,163    $  2,837   $  2,894      $2,840
Commercial                                                          2,743          2,763       2,595      2,559       2,485
Industrial                                                          2,237          2,267       2,139      2,136       2,206
Other                                                                   1             79          76         76          72
----------------------------------------------------------------------------------------------------------------------------
Total retail                                                        8,086          8,272       7,647      7,665       7,603
Sales for resale within service area                                  350            374         376        409         399
Sales for resale outside service area                                 473            522         510        429         415
----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity                            8,909          9,168       8,533      8,503       8,417
Southern Energy                                                     2,268          1,903       3,837      1,683         643
Other revenues                                                        408            332         241        172         120
----------------------------------------------------------------------------------------------------------------------------
Total                                                             $11,585        $11,403     $12,611    $10,358      $9,180
============================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential                                                        43,402         43,503      39,217     40,117      39,147
Commercial                                                         43,387         41,737      38,926     37,993      35,938
Industrial                                                         56,210         55,331      54,196     52,798      51,644
Other                                                                 945            929         903        911         863
----------------------------------------------------------------------------------------------------------------------------
Total retail                                                      143,944        141,500     133,242    131,819     127,592
Sales for resale within service area                                9,440          9,847       9,884     10,935       9,472
Sales for resale outside service area                              12,929         12,988      13,761     10,777       9,143
----------------------------------------------------------------------------------------------------------------------------
Total                                                             166,313        164,335     156,887    153,531     146,207
============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                                          7.15           7.27        7.23       7.21        7.25
Commercial                                                           6.32           6.62        6.67       6.74        6.91
Industrial                                                           3.98           4.10        3.95       4.04        4.27
Total retail                                                         5.62           5.85        5.74       5.81        5.96
Sales for resale                                                     3.68           3.92        3.75       3.86        4.38
Total sales                                                          5.36           5.58        5.44       5.54        5.76
Average Annual Kilowatt-Hour
   Use Per Residential Customer                                    13,107         13,379      12,296     12,824      12,722
Average Annual Revenue Per Residential Customer                   $937.81        $972.89     $889.50    $925.12     $922.83
Plant Nameplate Capacity Owned (year-end) (megawatts)              31,197         31,161      31,146     31,076      30,733
Maximum Peak-Hour Demand (megawatts):
Winter                                                             25,203         21,108      22,969     22,631      21,422
Summer                                                             30,578         28,934      27,334     27,190      27,420
System Reserve Margin (at peak) (percent)                             8.5           12.8        15.0       14.0         9.4
Annual Load Factor (percent)                                         59.2           60.0        59.4       62.3        59.5
Plant Availability (percent):
Fossil-steam                                                         83.3           85.2        88.2       86.4        86.7
Nuclear                                                              89.9           87.8        88.8       89.7        88.3
----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                                 73.1           72.8        74.7       73.3        72.5
Nuclear                                                              15.7           15.4        16.5       16.7        16.4
Hydro                                                                 2.3            3.9         4.3        4.1         4.1
Oil and gas                                                           2.8            3.3         1.7        1.5         1.7
Purchased power                                                       6.1            4.6         2.8        4.4         5.3
----------------------------------------------------------------------------------------------------------------------------
Total                                                               100.0          100.0       100.0      100.0       100.0
============================================================================================================================

</TABLE>



                                                                  II-47

<PAGE>



                              ALABAMA POWER COMPANY

                                FINANCIAL SECTION



                                      II-48

<PAGE>
MANAGEMENT'S REPORT
Alabama Power Company 1999 Annual Report


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

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

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

    The audit committee of the board of directors, composed of directors who are
not employees, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.

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

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



/s/Elmer B. Harris
Elmer B. Harris
President
and Chief Executive Officer

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


February 16, 2000



                                        II-49

<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Alabama Power Company:

We have audited the accompanying balance sheets and statements of capitalization
of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary
of Southern Company) as of December 31, 1999 and 1998, and the related
statements of income, common stockholder's equity, and cash flows for each of
the three years in the period ended December 31, 1999. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

    We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

    In our opinion, the financial statements (pages 11-59 through 11-77)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1999 and 1998, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.



/s/Arthur Andersen LLP
Birmingham, Alabama
February 16, 2000







                                       II-50

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1999 Annual Report


RESULTS OF OPERATIONS

Earnings

Alabama Power Company's 1999 net income after dividends on preferred stock was
$400 million, representing a $23 million (6 percent) increase from the prior
year. This improvement is primarily attributable to a decrease in amortization
related to premiums paid to reacquire debt pursuant to an Alabama Public Service
Commission (APSC) order. See Note 3 to the financial statements under "Retail
Rate Adjustment Procedures" for additional details.

    In 1998, earnings were $377 million, representing a 0.3 percent increase
from the prior year. This increase was due to increased retail energy sales as a
result of hot weather in the second quarter of 1998, compared to very mild
weather for the same period in 1997 and a strong economy in the Company's
service territory. However, earnings were offset by an increase in non-fuel
operation and maintenance expenses and an increase in the amortization related
to premiums paid to reacquire debt pursuant to an APSC order.

    The return on average common equity for 1999 was 13.85 percent compared to
13.63 percent in 1998, and 13.76 percent in 1997.

Revenues

Operating revenues for 1999 were $3.4 billion, reflecting a slight decrease from
1998. The following table summarizes the principal factors that have affected
operating revenues for the past three years:

                              Increase (Decrease) From Prior Year
                           -----------------------------------------
                                1999             1998           1997
                           -----------------------------------------
                                           (in thousands)
Retail --
Growth and price
  changes                   $ 27,893         $ 75,642       $ 33,813
Weather                      (17,871)          55,282        (22,973)
Fuel cost recovery
  and other                   20,418          138,944         31,353
---------------------------------------------------------------------
Total retail                  30,440          269,868         42,193
---------------------------------------------------------------------
Sales for resale --
  Non affiliates             (33,596)          17,950         39,354
  Affiliates                 (11,123)         (58,233)       (54,825)
---------------------------------------------------------------------
Total sales for resale       (44,719)         (40,283)       (15,471)
Other operating
  revenues                    13,380            7,677          1,614
---------------------------------------------------------------------
Total operating
  revenues                  $   (899)        $237,262       $ 28,336
=====================================================================
Percent change                 (0.03)%           7.53%          0.91%
---------------------------------------------------------------------

    Retail revenues of $2.8 billion in 1999 increased
$30 million (1.1 percent) from the prior year, compared with an increase of $270
million (10.7 percent) in 1998. The primary contributors to the increase in
revenues in 1999 were continued growth in the Company's service territory, as
well as an increase in fuel revenues. These increases were offset by the effect
of milder temperatures in 1999 as compared to 1998.

    The $13 million (25.2 percent) increase in other operating revenues in 1999
as compared to 1998 was due primarily to an increase in steam sales in
conjunction with the operation of the Company's co-generation facilities. The
increase is the result of two new co-generation facilities placed in service in
1999.

    Retail revenues in 1998 increased $270 million (10.7 percent) over 1997. The
predominant factors causing the rise in revenues in 1998 were the positive
impact of weather on energy sales, continued growth throughout the state, and


                                       II-51


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report


increased fuel revenues. Fuel revenues were higher in 1998 as compared to 1997
due to higher fuel costs and an increase in purchased power. Fuel revenues
generally represent the direct recovery of fuel expense, including the fuel
component of purchased energy, and therefore have no effect on net income.

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

                           1999           1998          1997
                 -------------------------------------------
                                    (in millions)
 Capacity                  $122           $142          $136
 Energy                     112            118           135
 ------------------------------------------------------------
 Total                     $234           $260          $271
=============================================================

    Capacity revenues from non-affiliates decreased 13.9 percent in 1999
compared to the prior year. This decrease is attributable to the lowering of the
equity return under formula rate contracts, as well as other adjustments and
true-ups related to contractual pricing. Capacity revenues from non-affiliates
in 1998 increased 4.1 percent compared to 1997.

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

    Kilowatt-hour (KWH) sales for 1999 and the percent change by year were as
follows:

                              KWH          Percent Change
                       -------------------------------------------
                              1999   1999       1998       1997
                       -------------------------------------------
                        (millions)

Residential                15,699    (0.6)%     10.2%      (1.8)%
Commercial                 12,314     3.4        5.1        3.9
Industrial                 21,943     1.7        4.2        3.6
Other                         201     2.3        8.3       (6.3)
                       -----------
Total retail               50,157     1.4        6.2        1.9
Sales for resale -
   Non-affiliates          12,438     5.0       (3.2)      29.9
   Affiliates               5,032   (15.8)     (33.5)     (12.6)
                       -----------
Total                      67,627     0.5%      (0.9)%      3.7%
------------------------------------------------------------------

    The increases in 1999 and 1998 retail energy sales were primarily due to the
strength of business and economic conditions in the Company's service area. In
1998, residential energy sales experienced a 10.2 percent increase over the
prior year primarily as a result of hot weather in the second quarter, compared
to very mild weather in the second quarter of 1997. Assuming normal weather,
sales to retail customers are projected to grow approximately 2.9 percent
annually on average during 2000 through 2004.

Expenses

Total operating expenses of $2.5 billion for 1999 were down $13.4 million or 0.5
percent compared with 1998. This decrease was mainly due to a $15 million
decrease in fuel and purchased power costs and a $23 million decrease in
maintenance expense, offset by an increase in taxes other than income taxes of
$12 million.

    Total operating expenses of $2.5 billion for 1998 were up $203 million or
8.8 percent compared with 1997. This increase was mainly due to a $107 million
increase in purchased power expenses, accompanied by a $58 million increase in
maintenance expense.

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


                                       II-52

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report


fuel per net KWH generated were as follows:

                                    ----------------------------
                                     1999      1998       1997
                                    ----------------------------
Total generation
 (billions of KWHs)                    63        63         65
Sources of generation
    (percent) --
      Coal                             72        72         72
      Nuclear                          20        18         20
      Hydro                             5         8          8
      Oil & Gas                         3         2          *
Average cost of fuel per net
    KWH generated
     (cents) --                      1.44      1.54       1.49
----------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.

    Total fuel and purchased power costs of $1.1 billion in 1999 decreased $15
million (1 percent), while total energy sales increased 329 million kilowatt
hours (0.5 percent) compared with the amounts recorded in 1998. Continued
efforts to control energy costs helped lower the average cost of fuel per net
kilowatt hour generated in 1999.

    Fuel and purchased power costs in 1998 increased $111 million (11 percent)
over 1997 due primarily to lower levels of nuclear and hydro generation, which
were replaced by the use of peaking units and purchased power.

    Purchased power consists primarily of purchases from affiliates in the
Southern electric system. Purchased power transactions among the Company and its
affiliates will vary from period to period depending on demand, the
availability, and the variable production cost of generating resources at each
company.

    The 7.5 percent decrease in maintenance expense in 1999 as compared to 1998
is primarily attributable to a decrease in distribution expenses. The 23.8
percent increase in maintenance expenses in 1998 is attributable to (i) an
increase in the maintenance of overhead lines, (ii) the write-off of obsolete
steam and nuclear generating plant inventory, and (iii) additional accruals to
partially replenish the natural disaster reserve.

    Depreciation and amortization expense increased 2.6 percent in 1999 and
1998. These increases reflect additions to property, plant, and equipment.

    Taxes other than income taxes increased $12 million (6.0 percent) in 1999 as
compared to 1998. This increase is attributable to increases in real and
personal property taxes and public utility license taxes.

    Total net interest and other charges decreased $38 million (12.3 percent) in
1999. This decrease results primarily from a decrease in the amortization of
premiums on reacquired debt pursuant to an APSC order. Total net interest and
other charges increased $55.7 million (22 percent) in 1998 primarily due to an
increase in the amortization of premiums on reacquired debt, pursuant to an APSC
order. See Note 3 to the financial statements under "Retail Rate Adjustment
Procedures" for additional details.

Effects of Inflation

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

Future Earnings Potential

The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors, including the ability of the Company to achieve energy sales
growth in a less regulated, more competitive environment.

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




                                      II-53



<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report


    Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included weather, competition, new short and long-term contracts with
neighboring utilities, energy conservation practiced by customers, the
elasticity of demand, and the rate of economic growth in the Company's
traditional service area.

    The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and/or commercial customers and sell excess energy
generation to other utilities. Also, electricity sales for resale rates are
being driven down by wholesale transmission access and numerous potential new
energy suppliers, including power marketers and brokers. The Company is
aggressively working to maintain and expand its share of wholesale business in
the Southeastern power markets.

   Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry continues to
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of the Company to recover its investments, including the
regulatory assets described in Note 1 to the financial statements, could have a
material adverse effect on the financial condition and results of operations.

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

   On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
the formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including Southern Company, are required
to make a filing by October 15, 2000. The filing must contain either a proposal
for RTO participation or a description of the efforts made to participate in an
RTO, the reasons for non-participation, any obstacles to participation, and any
plans for further work toward participation. The RTOs that are proposed in the
filings should be operational by December 15, 2001. The Company is evaluating
this issue and formulating its response. The outcome of this matter cannot
presently be determined.

    Rates to retail customers served by the Company are regulated by the APSC.
Rates for the Company can be adjusted periodically within certain limitations
based on earned retail rate of return compared with an allowed return. In June
1995, the APSC issued an order granting the Company's request for gradual
adjustments to move toward parity among customer classes. This order also calls
for a moratorium on any periodic retail rate increases (but not decreases) until
2001.

    In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. In April 1997,
the APSC issued an additional order authorizing the Company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the Company. See Note 3 to
the financial statements for


                                       II-54

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report


information about this and other matters.

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

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

    The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry --
including the Company -- regarding the recognition, measurement, and
classification in the financial statements of decommissioning costs for nuclear
generating facilities. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to the retirement of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs of
retiring the Company's nuclear and other facilities may be required to be
recorded as liabilities in the Balance Sheets. Also, the annual provisions for
such costs could change. Because of the Company's current ability to recover
asset retirement costs through rates, these changes would not have a significant
adverse effect on results of operations. See Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning" for additional information.

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

New Accounting Standard

The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 1, 2001. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.

Year 2000 Challenge

The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.

    For the Company, original projected total costs for Year 2000 readiness,
including the Company's share of costs of Southern Nuclear Operating Company,
were approximately $36 million; revised projected costs are $33 million. These
costs include labor necessary to identify, test, and renovate affected devices
and systems, and costs for fulfilling reporting requirements to state and
federal agencies. From its inception through December 31, 1999, the Year 2000
program costs, recognized primarily as expense, amounted to $32 million.

Exposure to Market Risk

Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market. Realized gains and losses
are recognized in the income statement as incurred. At December 31, 1999,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Also, based on the Company's
overall interest rate exposure at December 31, 1999, a near-term 100 basis point
change in interest rates would not materially affect the financial statements.


                                       II-55
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report


FINANCIAL CONDITION

Overview

The Company's financial condition remained stable in 1999. This stability is the
continuation over recent years of growth in retail energy sales and cost control
measures combined with a significant lowering of the cost of capital, achieved
through the refinancing and/or redemption of higher-cost long-term debt and
preferred stock.

    The Company had gross property additions of $809 million in 1999. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.

Capital Structure

The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.4 percent in 1999 and 1998, and 44.7 percent in 1997.

    During 1999, the Company issued $650 million of senior notes, the proceeds
of which were used primarily to redeem first mortgage bonds and repay short-term
indebtedness, and the Company redeemed $50 million of preferred stock.

    Additionally, in February 1999, Alabama Power Capital Trust III, of which
the Company owns all of the common securities, issued $50 million of auction
rate mandatorily redeemable preferred securities. See Note 9 to the financial
statements for additional information.

Capital Requirements

Capital expenditures are estimated to be $831 million for 2000, $743 million for
2001, and $860 million for 2002. See Note 4 to the financial statements for
additional details.

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

Other Capital Requirements

In addition to the funds needed for the capital budget, approximately $100
million will be required by the end of 2000 for maturities of first mortgage
bonds. Also, the Company will continue to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.

Environmental Matters

On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action against the Company in the U. S. District Court. The complaint alleges
violations of the prevention of significant deterioration and new source review
provisions of the Clean Air Act with respect to coal-fired generating facilities
at the Company's Plants Miller, Barry and Gorgas. The civil action requests
penalties and injunctive relief, including an order requiring the installation
of the best available control technology at the affected units. The EPA
concurrently issued a notice of violation to the Company relating to these
specific facilities, as well as Plants Greene County and Gaston. In early 2000,
the EPA filed a motion to amend its complaint to add the violations alleged in
its notice of violation.  The complaint and the notice of violation are similar
to those brought against and issued to several other electric utilities. The
complaint and the notice of violation allege that the Company failed to secure
necessary permits or install additional pollution control equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. The Company believes that it complied with
applicable laws and EPA regulations and interpretations in effect at the time
the work in question took place. The Clean Air Act authorizes civil penalties
of up to $27,500 per day per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly financial
condition if such costs are not recovered through regulated rates.




                                      II-56
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report


    In November 1990, the Clean Air Act was signed into law. Title IV of the
Clean Air Act -- the acid rain compliance provision of the law - significantly
affected the integrated Southeast utilities of Southern Company, including
Alabama Power. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.

   Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $25
million for the Company.

    For Phase II sulfur dioxide compliance, the Company currently uses emission
allowances and increased fuel switching, and/or the installation of flue gas
desulfurization equipment at selected plants. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits. Compliance for Phase II increased total
estimated construction expenditures in 1999 by approximately $65 million.

    The State of Alabama and the EPA are currently evaluating draft plans to
reach attainment with the one hour standard for ozone in the Birmingham
non-attainment area. Provisions of that plan would require nitrogen oxide
reductions at certain Company facilities by May 2003. The Company estimates the
capital cost to comply with the plan to be approximately $138 million, all of
which remains to be spent.

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

    In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision makes the standards significantly
more stringent. In September 1998, the EPA issued the final regional nitrogen
oxide reduction rule to the states for implementation. The final rule affects 22
states including Alabama. The EPA's July 1997 standards and the September 1998
rule are being challenged in the courts by several states and industry groups.
Implementation of the final state rules for these three initiatives could
require substantial further reductions in nitrogen oxide and sulfur dioxide
emissions from fossil-fired generating facilities and other industries in these
states. Additional compliance costs and capital expenditures resulting from the
implementation of these rules and standards cannot be determined until the
results of legal challenges are known, and the states have adopted their final
rules.

   The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: additional controls for hazardous
air pollutant emissions and control strategies to reduce regional haze. The
impact of any new standards will depend on the development and implementation of
applicable regulations.

    In addition to rules and pending changes to rules under the Clean Air Act,
the Company must comply with other environmental laws and regulations including
water discharge permits, solid and hazardous waste disposal, use of materials
controlled by the Toxic Substances Control Act, and reporting requirements under
the Comprehensive Environmental Response, Compensation, and Liability Act. Under
these various requirements and regulations, the Company could incur costs to
implement water discharge requirements, clean up properties containing hazardous
substances, or replace equipment rendered useless by changing requirements. The
exact impact of any requirements would depend on specific regulatory actions and
cannot be determined at this time.

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




                                      II-57
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report


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

Sources of Capital

The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company has no restrictions on the
amounts of unsecured indebtedness it may incur. However, to issue additional
first mortgage bonds and preferred stock, the Company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The Company's coverages are at a level that would permit any
necessary amount of security sales at current interest and dividend rates.

    As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the Company has established external trust funds for nuclear decommissioning
costs. In 1994, the Company also established an external trust fund for
postretirement benefits as ordered by the APSC. The cumulative effect of funding
these items over a long period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."

Cautionary Statement Regarding Forward-Looking
Information

The Company's 1999 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information. Accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the Company's markets; potential business strategies -- including
acquisitions or dispositions of assets or internal restructuring -- that may be
pursued by Southern Company; state and federal rate regulation; changes in or
application of environmental and other laws and regulations to which the Company
is subject; political, legal and economic conditions and developments; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; and other
factors discussed in the reports--including Form 10-K--filed from time to time
by the Company with the Securities and Exchange Commission.



                                       II-58



<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------------
                                                                        1999                1998               1997
------------------------------------------------------------------------------------------------------------------------
                                                                                     (in thousands)
<S>                                                                   <C>                 <C>                <C>
Operating Revenues:
Retail sales                                                          $2,811,117          $2,780,677         $2,510,809
Sales for resale --
  Non-affiliates                                                         415,377             448,973            431,023
  Affiliates                                                              92,439             103,562            161,795
Other revenues                                                            66,541              53,161             45,484
------------------------------------------------------------------------------------------------------------------------
Total operating revenues                                               3,385,474           3,386,373          3,149,111
------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                                   855,632             900,309            896,014
  Purchased power --
   Non-affiliates                                                         93,204              92,998             41,795
   Affiliates                                                            180,563             150,897             95,538
  Other                                                                  531,696             527,954            510,203
Maintenance                                                              277,724             300,383            242,691
Depreciation and amortization                                            347,574             338,822            330,377
Taxes other than income taxes                                            204,645             193,049            185,062
------------------------------------------------------------------------------------------------------------------------
Total operating expenses                                               2,491,038           2,504,412          2,301,680
------------------------------------------------------------------------------------------------------------------------
Operating Income                                                         894,436             881,961            847,431
Other Income (Expense):
Interest income                                                           55,896              68,553             37,844
Equity in earnings of unconsolidated subsidiaries (Note 6)                 2,650               5,271              5,250
Other, net                                                               (24,861)            (37,050)           (39,506)
------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                                928,121             918,735            851,019
------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt                                               191,895             192,426            167,172
Interest on notes payable                                                  9,865              11,012             22,787
Amortization of debt discount, premium and expense, net (Note 3)          11,159              42,494              9,645
Other interest charges                                                    32,316              40,008             31,250
Distributions on preferred securities of subsidiary (Note 9)              24,662              22,354             21,763
------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                                    269,897             308,294            252,617
------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                             658,224             610,441            598,402
Income taxes (Note 8)                                                    241,880             218,575            207,877
------------------------------------------------------------------------------------------------------------------------
Net Income                                                               416,344             391,866            390,525
Dividends on Preferred Stock                                              16,464              14,643             14,586
------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock                         $  399,880          $  377,223         $  375,939
========================================================================================================================
The accompanying notes are an integral part of these statements.


</TABLE>

                                                                  II-59

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report

-------------------------------------------------------------------------------------------------------------------------
                                                                     1999                 1998                1997
-------------------------------------------------------------------------------------------------------------------------
                                                                                     (in thousands)
<S>                                                                   <C>                 <C>                 <C>
Operating Activities:
Net income                                                            $ 416,344           $  391,866          $  390,525
Adjustments to reconcile net income
 to net cash provided from operating activities --
       Depreciation and amortization                                    403,332              425,167             394,572
       Deferred income taxes and investment tax credits, net             29,039               79,430             (12,429)
       Other, net                                                       (12,661)             (66,739)            (11,353)
       Changes in certain current assets and liabilities --
          Receivables, net                                               33,509               49,747             (30,268)
          Fossil fuel stock                                              (1,344)              (9,052)              7,518
          Materials and supplies                                        (17,968)              11,932               6,191
          Accounts payable                                              (38,556)              26,583              (9,745)
          Energy cost recovery, retail                                  (97,869)             (95,427)              7,108
          Other                                                           5,930               (9,803)             13,318
-------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                             719,756              803,704             755,437
-------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                               (809,044)            (610,132)           (451,167)
Other                                                                   (72,218)             (52,940)            (51,791)
-------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                 (881,262)            (663,072)           (502,958)
-------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                96,824             (306,882)            (57,971)
Proceeds --
  Other long-term debt                                                  751,650            1,462,990             258,800
  Preferred securities                                                   50,000                    -             200,000
  Preferred stock                                                             -              200,000                   -
  Capital contributions from parent company                             204,347               30,000                   -
Redemptions --
  First mortgage bonds                                                 (470,000)            (771,108)            (74,951)
  Other long-term debt                                                 (104,836)            (107,776)               (951)
  Preferred stock                                                       (50,000)             (88,000)           (184,888)
Payment of preferred stock dividends                                    (15,788)             (15,596)            (22,524)
Payment of common stock dividends                                      (399,600)            (367,100)           (339,600)
Other                                                                   (15,864)             (66,869)            (16,024)
-------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities                   46,733              (30,341)           (238,109)
-------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                (114,773)             110,291              14,370
Cash and Cash Equivalents at Beginning of Period                        134,248               23,957               9,587
-------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                            $  19,475           $  134,248           $  23,957
=========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
  Interest (net of amount capitalized)                                 $229,305             $234,360            $209,919
  Income taxes (net of refunds)                                         170,121              188,942             207,653
-------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.



                                                                  II-60
</TABLE>

<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------
Assets                                                                             1999                     1998
-----------------------------------------------------------------------------------------------------------------
                                                                                          (in thousands)

Current Assets:
<S>                                                                            <C>                     <C>
Cash and cash equivalents                                                    $   19,475              $   134,248
Receivables --
  Customer accounts receivable                                                  265,900                  272,872
  Unrecovered retail fuel clause revenue                                        168,627                   70,758
  Other accounts and notes receivable                                            42,137                   32,394
  Affiliated companies                                                           40,083                   39,981
  Accumulated provision for uncollectible accounts                               (4,117)                  (1,855)
Refundable income taxes                                                          17,997                   52,117
Fossil fuel stock, at average cost                                               84,582                   83,238
Materials and supplies, at average cost                                         167,637                  149,669
Other                                                                            46,011                   45,550
-----------------------------------------------------------------------------------------------------------------
Total current assets                                                            848,332                  878,972
-----------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Note 1)                                                          11,783,078               11,352,838
Less accumulated provision for depreciation                                   4,901,384                4,666,513
-----------------------------------------------------------------------------------------------------------------
                                                                              6,881,694                6,686,325
Nuclear fuel, at amortized cost                                                 106,836                   95,575
Construction work in progress                                                   715,153                  525,359
-----------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                          7,703,683                7,307,259
-----------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 6)                       34,891                   34,298
Nuclear decommissioning trusts (Note 1)                                         286,653                  232,183
Other                                                                            12,156                   12,915
-----------------------------------------------------------------------------------------------------------------
Total other property and investments                                            333,700                  279,396
-----------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8)                               330,405                  362,953
Prepaid pension costs                                                           213,971                  169,393
Debt expense, being amortized                                                     9,563                    8,602
Premium on reacquired debt, being amortized                                      83,895                   83,440
Department of Energy assessments (Note 1)                                        27,685                   31,088
Other                                                                            97,470                  104,595
-----------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                         762,989                  760,071
-----------------------------------------------------------------------------------------------------------------
Total Assets                                                                 $9,648,704               $9,225,698
=================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>


                                                                  II-61



<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                                1999                     1998
------------------------------------------------------------------------------------------------------------------
                                                                                           (in thousands)

<S>                                                                         <C>                      <C>
Current Liabilities:
Securities due within one year (Note 11)                                      $  100,943               $  521,209
Notes payable                                                                     96,824                        -
Accounts payable --
  Affiliated                                                                      91,315                   79,844
  Other                                                                          140,842                  188,074
Customer deposits                                                                 31,704                   29,235
Taxes accrued --
  Income taxes                                                                   100,569                   82,219
  Other                                                                           18,295                   17,559
Interest accrued                                                                  26,365                   38,166
Vacation pay accrued                                                              30,112                   28,390
Other                                                                             84,267                   79,095
------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                        721,236                1,063,791
------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                   3,190,378                2,646,566
------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8)                                     1,240,344                1,202,971
Deferred credits related to income taxes (Note 8)                                265,102                  315,735
Accumulated deferred investment tax credits                                      260,367                  271,611
Employee benefits provisions                                                      82,298                   81,115
Prepaid capacity revenues (Note 7)                                                79,703                   96,080
Other                                                                            155,901                  149,250
------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                   2,083,715                2,116,762
------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
  securities of subsidiary trusts holding company junior
  subordinated notes (See accompanying statements) (Note 9)                      347,000                  297,000
------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements)                         317,512                  317,512
------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                      2,988,863                2,784,067
------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                    $9,648,704               $9,225,698
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>


                                                                  II-62

<PAGE>
<TABLE>
<CAPTION>

STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report

----------------------------------------------------------------------------------------------------------------------------------
                                                                           1999             1998            1999             1998
----------------------------------------------------------------------------------------------------------------------------------
                                                                                (in thousands)              (percent of total)
Long-Term Debt:
First mortgage bonds --

       Maturity                           Interest Rates
       --------                           --------------
       <S>                               <C>                          <C>            <C>                       <C>            <C>
       August 1, 1999                     6.375%                      $       -        $ 170,000
       March 1, 2000                      6.00%                         100,000          100,000
       January 1, 2003                    7.00%                               -          125,000
       February 1, 2003                   6.75%                               -          175,000
       2023 through 2024                  7.30% - 9.00%                 500,000          500,000
----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                              600,000        1,070,000
----------------------------------------------------------------------------------------------------------------------------------
Senior notes --
       5.35% due November 15, 2003                                      156,200          156,200
       7.125% due August 15, 2004                                       250,000              -
       5.49% due November 1, 2005                                       225,000          225,000
       7.125% due October 1, 2007                                       200,000              -
       5.375% due October 1, 2008                                       160,000          160,000
       6.25% to 7.125% due 2010-2048                                  1,207,622        1,008,800
----------------------------------------------------------------------------------------------------------------------------------
Total senior notes                                                    2,198,822        1,550,000
----------------------------------------------------------------------------------------------------------------------------------
Other  long-term debt --
    Pollution control revenue bonds --
      Collateralized:
        5.50% to 6.50% due 2023-2024                                     24,400          126,050
        Variable rates (4.75% to 4.85% at 1/1/00)
         due 2015-2017                                                   89,800           89,800
      Non-collateralized:
        7.25% due 2003                                                        -            1,000
        Variable rates (3.50% to 6.03% at 1/1/00)
          due 2021-2028                                                 425,940          324,290
----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                              540,140          541,140
----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations                                             5,111            6,119
----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net                                (52,752)         (49,484)
----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
 requirement -- $215.9 million)                                       3,291,321        3,117,775
Less amount due within one year                                         100,943          471,209
----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year                  $3,190,378       $2,646,566           46.6%            43.8%
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>





                                                                  II-63

<PAGE>
<TABLE>
<CAPTION>

STATEMENTS OF CAPITALIZATION (continued) At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report

----------------------------------------------------------------------------------------------------------------------------------
                                                                           1999             1998            1999             1998
----------------------------------------------------------------------------------------------------------------------------------
                                                                                 (in thousands)             (percent of total)
<S>                                                                   <C>              <C>                <C>              <C>
Company Obligated Mandatorily
   Redeemable Preferred Securities:
$25 liquidation value --
  7.375%                                                               $ 97,000          $97,000
  7.60%                                                                 200,000          200,000
  Auction rate (6.42% at 1/1/00)                                         50,000                -
---------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $25.6 million)                347,000          297,000             5.1              4.9
----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par or stated value --
  4.20% to 4.92%                                                         47,512           47,512
$25 par or stated value --
  5.20% to 5.83%                                                        200,000          200,000
Auction rates -- at 1/1/00
  4.22% to 4.50%                                                         70,000          120,000
----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $15.9 million)                    317,512          367,512
Less amount due within one year                                               -           50,000
----------------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year                              317,512          317,512             4.6              5.2
----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
  Authorized  - 6,000,000 shares
  Outstanding - 5,608,955 shares in 1999 and 1998
  Par value                                                             224,358          224,358
  Paid-in capital                                                     1,538,992        1,334,645
  Premium on Preferred Stock                                                 99               99
Retained earnings                                                     1,225,414        1,224,965
----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                                     2,988,863        2,784,067            43.7             46.1
----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                 $6,843,753       $6,045,145          100.0%           100.0%
==================================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>


                                                                  II-64

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report

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

                                                                                Premium on
                                                     Common         Paid-In     Preferred        Retained
                                                      Stock         Capital       Stock          Earnings            Total
-----------------------------------------------------------------------------------------------------------------------------
                                                                             (in thousands)

<S>                                                 <C>           <C>                 <C>       <C>              <C>
Balance at January 1, 1997                           $224,358      $1,304,645          $146      $1,185,128       $2,714,277
Net income after dividends on preferred stock               -               -             -         375,939          375,939
Cash dividends on common stock                              -               -             -        (339,600)        (339,600)
Other                                                       -               -           (47)              -              (47)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997                          224,358       1,304,645            99       1,221,467        2,750,569
Net income after dividends on preferred stock               -               -             -         377,223          377,223
Capital contributions from parent company                   -          30,000             -               -           30,000
Cash dividends on common stock                              -               -             -        (367,100)        (367,100)
Other                                                       -               -             -          (6,625)          (6,625)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                          224,358       1,334,645            99       1,224,965        2,784,067
Net income after dividends on preferred stock               -               -             -         399,880          399,880
Capital contributions from parent company                   -         204,347             -               -          204,347
Cash dividends on common stock                              -               -             -        (399,600)        (399,600)
Other                                                       -               -             -             169              169
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                         $224,358      $1,538,992           $99      $1,225,414       $2,988,863
=============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>



                                                                  II-65



<PAGE>
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1999 Annual Report


1.   SUMMARY OF SIGNIFICANT ACCOUNTING
     POLICIES

General

Alabama Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five integrated Southeast utilities,
Southern Company Services (SCS), Southern Communications Services (Southern
LINC), Southern Company Energy Solutions, Southern Energy, Inc. (Southern
Energy), Southern Nuclear Operating Company (Southern Nuclear), and other direct
and indirect subsidiaries. The integrated Southeast utilities --Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company-- provide electric service in four
states. Contracts among the integrated Southeast utilities - related to
jointly-owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS
provides, at cost, specialized services to Southern Company and its subsidiary
companies. Southern LINC provides digital wireless communications services to
the integrated Southeast utilities and also markets these services to the public
within the Southeast. Southern Company Energy Solutions develops new business
opportunities related to energy products and services. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Energy acquires,
develops, builds, owns, and operates power production and delivery facilities
and provides a broad range of energy-related services to utilities and
industrial companies in selected countries around the world. Southern Energy
businesses include independent power projects, integrated utilities, a
distribution company, and energy trading and marketing businesses outside the
southeastern United States.

    Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The Company follows generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by its respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from
those estimates.

   Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.

Related-Party Transactions

The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool transactions. Costs for these services amounted to $218 million, $201
million, and $154 million during 1999, 1998, and 1997, respectively.

   The Company also has an agreement with Southern Nuclear to operate Plant
Farley and provide the following nuclear-related services at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting,
statistical, and employee relations; and other services with respect to business
and operations. Costs for these services amounted to $135 million, $137 million,
and $117 million during 1999, 1998, and 1997, respectively.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process.


                                       II-66

<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


   Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:

                                               1999        1998
                                         -----------------------
                                              (in millions)
Deferred income tax charges                   $ 330       $ 363
Deferred income tax credits                    (265)       (316)
Premium on reacquired debt                       84          83
Department of Energy assessments                 28          31
Vacation pay                                     30          28
Natural disaster reserve                        (19)        (19)
Other, net                                       59          51
----------------------------------------------------------------
Total                                         $ 247       $ 221
================================================================

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

Revenues and Fuel Costs

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Alabama, and to wholesale customers in the southeast. The
Company accrues revenues for services rendered but unbilled at the end of each
fiscal period. Fuel costs are expensed as the fuel is used. The Company's
electric rates include provisions to adjust billings for fluctuations in fuel
and the energy component of purchased power costs. Revenues are adjusted for
differences between recoverable fuel costs and amounts actually recovered in
current regulated rates.

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

    Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $63
million in 1999, $59 million in 1998, and $68 million in 1997. The Company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent fuel in January 1998 as required by the contract, and the Company is
pursuing legal remedies against the government for breach of contract.
Sufficient storage capacity currently is available to permit operation into 2009
and 2013 at Plant Farley units 1 and 2, respectively. Planning for additional
on-site spent fuel storage capacity at Plant Farley is in progress, with the
intent to place additional on-site spent fuel storage capacity in operation as
early as 2005. In addition, through Southern Nuclear, the Company is a member of
Private Fuel Storage, LLC, a joint utility effort to develop a private spent
fuel storage facility for temporary storage of spent nuclear fuel. This facility
is planned to begin operation as early as the year 2003.

    Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is funded in part by
a special assessment on utilities with nuclear plants. This assessment will be
paid over a 15-year period, which began in 1993. This fund will be used by the
DOE for the decontamination and decommissioning of its nuclear fuel enrichment
facilities. The law provides that utilities will recover these payments in the
same manner as any other fuel expense. The Company estimates its remaining
liability at December 31, 1999, under this law to be approximately $28 million.
This obligation is recognized in the accompanying Balance Sheets.

Depreciation and Nuclear Decommissioning

Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.2 percent in 1999 and 1998, and 3.3 percent in 1997. When property subject to
depreciation is retired or otherwise disposed of in the normal course of
business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Depreciation expense includes an amount for the expected cost
of decommissioning nuclear facilities and removal of other facilities.

    Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial nuclear power reactors to establish a plan for providing,
with reasonable assurance, funds for decommissioning. The Company has




                                       II-67
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


established external trust funds to comply with the NRC's regulations. Amounts
previously recorded in internal reserves are being transferred into the external
trust funds over periods approved by the APSC. The NRC's minimum external
funding requirements are based on a generic estimate of the cost to decommission
the radioactive portions of a nuclear unit based on the size and type of
reactor. The Company has filed plans with the NRC to ensure that -- over time --
the deposits and earnings of the external trust funds will provide the minimum
funding amounts prescribed by the NRC.

    Site study cost is the estimate to decommission the facility as of the site
study year, and ultimate cost is the estimate to decommission the facility as of
retirement date. The estimated costs of decommissioning -- both site study costs
and ultimate costs -- based on the most current study for Plant Farley were as
follows:

  Site study basis (year)                           1998

  Decommissioning periods:
      Beginning year                                2017
      Completion year                               2031
  -------------------------------------------------------------
                                                (in millions)
  Site study costs:
      Radiated structures                        $    629
      Non-radiated structures                          60
  -------------------------------------------------------------
  Total                                          $    689
  =============================================================
                                                (in millions)
  Ultimate costs:
      Radiated structures                        $  1,868
      Non-radiated structures                         178
  -------------------------------------------------------------
  Total                                          $  2,046
  =============================================================

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

    Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the APSC. The amount expensed in 1999 and fund balances as of
December 31, 1999 were:

                                                (in millions)
  Amount expensed in 1999                          $   18
  -------------------------------------------------------------

  Accumulated provisions:
      External trust funds, at fair value          $  287
      Internal reserves                                40
  -------------------------------------------------------------
  Total                                            $  327
  =============================================================

    All of the Company's decommissioning costs are approved for ratemaking.
Significant assumptions include an estimated inflation rate of 4.5 percent and
an estimated trust earnings rate of 7.0 percent. The Company expects the APSC to
periodically review and adjust, if necessary, the amounts collected in rates for
the anticipated cost of decommissioning.

Income Taxes

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

Allowance For Funds Used During Construction
(AFUDC)

AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rate used to determine the amount of
allowance was 8.8 percent in 1999, 9.0 percent in 1998, and 5.8 percent in 1997.
AFUDC, net of income tax, as a percent of net income after dividends on
preferred stock was 4.7 percent in 1999, 1.8 percent in 1998, and 0.8 percent in
1997.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other


                                       II-68
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


benefits; and the estimated cost of funds used during construction. The cost of
maintenance, repairs and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property (exclusive of minor
items of property) is capitalized.

Financial Instruments

The Company's financial instruments for which the carrying amount did not
approximate fair value at December 31 are as follows:

                                        Carrying         Fair
                                         Amount         Value
                                      -------------------------
                                             (in millions)

 Long-term debt:
   At December 31, 1999                  $3,286         $3,045
   At December 31, 1998                   3,112          3,195
 Preferred Securities:
   At December 31, 1999                     347            299
   At December 31, 1998                     297            307
 --------------------------------------------------------------

   The fair value for long-term debt and preferred securities was based on
either closing market prices or closing prices of comparable instruments.

Cash and Cash Equivalents

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

Materials and Supplies

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

Natural Disaster Reserve

In September 1994, in response to a request by the Company, the APSC issued an
order allowing the Company to establish a Natural Disaster Reserve. Regulatory
treatment allows the Company to accrue $250 thousand per month, until the
maximum accumulated provision of $32 million is attained. However, in December
1995, the APSC approved higher accruals to restore the reserve to its authorized
level whenever the balance in the reserve declines below $22.4 million. At
December 31, 1999, the reserve balance was $19 million.

2.   RETIREMENT BENEFITS

The Company has defined benefit, trusteed, pension plans that cover
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all employees may become
eligible for such benefits when they retire. The Company funds trusts to the
extent deductible under federal income tax regulations or to the extent required
by the APSC and FERC. The measurement date for plan assets and obligations is
September 30 of each year.

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

                                          1999         1998
---------------------------------------------------------------
Discount                                  7.50%        6.75%
Annual salary increase                    5.00         4.25
Long-term return on plan assets           8.50         8.50
---------------------------------------------------------------

Pension Plan

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

                                            Projected
                                       Benefit Obligations
                                    ---------------------------
                                          1999          1998
---------------------------------------------------------------
                                             (in millions)
Balance at beginning of year              $868          $813
Service cost                                23            22
Interest cost                               57            59
Benefits paid                              (51)          (51)
Actuarial (gain) loss and
  employee transfers                       (24)           25
---------------------------------------------------------------
Balance at end of year                    $873          $868
===============================================================


                                          Plan Assets
                                    ---------------------------
                                     1999               1998
---------------------------------------------------------------
                                          (in millions)
Balance at beginning of year            $1,461        $1,521
Actual return on plan assets               245             9
Benefits paid                              (51)          (51)
Employee transfers                          (8)          (18)
---------------------------------------------------------------
Balance at end of year                  $1,647        $1,461
===============================================================

                                       II-69

<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


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

                                              1999       1998
---------------------------------------------------------------
                                              (in millions)
Funded status                               $  774     $  593
Unrecognized transition obligation             (25)       (30)
Unrecognized prior service cost                 36         39
Unrecognized net actuarial gain               (571)      (433)
---------------------------------------------------------------
Prepaid asset recognized in the
  Balance Sheets                            $  214     $  169
===============================================================

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

                                        1999     1998     1997
---------------------------------------------------------------
                                            (in millions)
Service cost                           $  23    $  22     $ 20
Interest cost                             57       59       58
Expected return on plan assets          (109)    (102)     (95)
Recognized net actuarial gain            (14)     (16)     (13)
Net amortization                          (2)      (2)      (2)
---------------------------------------------------------------
Net pension income                     $ (45)   $ (39)    $(32)
===============================================================

Postretirement Benefits

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

                                            Accumulated
                                        Benefit Obligations
                                    ---------------------------
                                         1999          1998
---------------------------------------------------------------
                                          (in millions)
Balance at beginning of year             $278          $252
Service cost                                5             5
Interest cost                              18            19
Benefits paid                             (10)          (12)
Actuarial (gain) loss and
  employee transfers                      (27)           14
---------------------------------------------------------------
Balance at end of year                   $264          $278
===============================================================

                                           Plan Assets
                                    ---------------------------
                                         1999          1998
---------------------------------------------------------------
                                          (in millions)
Balance at beginning of year             $137          $125
Actual return on plan assets               18             4
Employer contributions                     16            20
Benefits paid                             (10)          (12)
---------------------------------------------------------------
Balance at end of year                   $161          $137
===============================================================

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

                                              1999       1998
---------------------------------------------------------------
                                              (in millions)
Funded status                                $(103)     $(141)
Unrecognized transition obligation              53         57
Unrecognized net actuarial
  (gain) loss                                  (12)        22
Fourth quarter contributions                     8          8
---------------------------------------------------------------
Accrued liability recognized in the
  Balance Sheets                            $ (54)     $ (54)
===============================================================

    Components of the plans' net periodic cost were as follows:

                                         1999    1998     1997
---------------------------------------------------------------
                                            (in millions)
Service cost                            $   5    $  5     $  4
Interest cost                              18      18       18
Expected return on plan assets            (11)     (9)      (7)
Net amortization                            4       4        4
---------------------------------------------------------------
Net postretirement cost                 $ 16     $ 18     $ 19
===============================================================

      An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1999 as follows:

                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
                                           (in millions)
Benefit obligation                      $ 17         $ (15)
Service and interest costs                 1            (1)
===============================================================

Work Force Reduction Programs

The Company has incurred additional costs for work force reduction programs. The
costs related to these programs were $5.6 million, $19.4 million and $33.0
million for the years 1999, 1998 and 1997, respectively. In addition, certain
costs of these programs were deferred and are being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $1.2 million at
December 31, 1999.

                                       II-70
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


3.  CONTINGENCIES AND REGULATORY
    MATTERS

Lake Martin Litigation

On November 30, 1998, total judgments of nearly $53 million were entered in
favor of five plaintiffs against the Company and two large textile
manufacturers. The plaintiffs alleged that the manufacturers had discharged
certain polluting substances into a stream that empties into Lake Martin, a
hydroelectric reservoir owned by the Company, and that such discharges
had reduced the value of the plaintiffs' residential lots on Lake Martin. Of the
total amount of the judgments, $155 thousand was compensatory damages and the
remainder was punitive damages. The damages were assessed against all three
defendants jointly. The Company has appealed these judgments to the Supreme
Court of Alabama. While the Company believes that these judgments should be
reversed or set aside, the final outcome of this matter cannot now be
determined.

   Additional actions have been filed by other landowners in the same
subdivision on Lake Martin against the same defendants, including the Company.
The plaintiffs assert substantially the same allegations as in the current
proceeding being appealed. The final outcome of these actions cannot now be
determined.

Environmental Protection Agency Litigation

On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action against the Company in the U. S. District Court. The complaint alleges
violations of the prevention of significant deterioration and new source review
provision of the Clean Air Act with respect to coal-fired generating facilities
at the Company's Plants Miller, Barry and Gorgas. The civil action requests
penalties and injunctive relief, including an order requiring the installation
of the best available control technology at the affected units beginning at the
point of the alleged violations. The EPA concurrently issued a notice of
violation to the Company relating to these specific facilities, as well as
Plants Greene County and Gaston.  In early 2000, the EPA filed a motion to
amend its complaint to add the violations alleged in its notice of violation.
The complaint and the notice of violation are similar to those brought against
and issued to several other electric utilities. The complaint and the notice of
violation allege that the Company failed to secure necessary permits or install
additional pollution control equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit. Prior to January 30, 1997, the penalty was
$25,000 per day. An adverse outcome of this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows, and possibly financial condition if such costs are not
recovered through regulated rates.

Retail Rate Adjustment Procedures

In November 1982, the APSC adopted rates that provide for periodic adjustments
based upon the Company's earned return on end-of-period retail common equity.
The rates also provide for adjustments to recognize the placing of new
generating facilities in retail service. Both increases and decreases have been
placed into effect since the adoption of these rates. The rate adjustment
procedures allow a return on common equity range of 13.0 percent to 14.5 percent
and limit increases or decreases in rates to 4 percent in any calendar year.

    In June 1995, the APSC issued a rate order granting the Company's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.

    In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. In April 1997,
the APSC issued an additional order authorizing the Company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the Company. In 1998, the
Company - in accordance with the 1995 rate order - recorded $33 million of
additional amortization of premium on reacquired debt. The Company did not
record any additional amounts in 1999 or 1997.


                                       II-71
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


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

4.   CAPITAL BUDGET

The Company's capital expenditures are currently estimated to total $831 million
in 2000, $743 million in 2001, and $860 million in 2002. Some of the more
significant items included in the Company's capital budget are as follows:

(i)  The Company is replacing all six steam generators at Plant Farley. The
     estimated remaining costs associated with this project, which will be
     completed in 2001, amount to $100 million.

(ii) The Company is also constructing and installing 1,075 megawatts of capacity
     and associated substation facilities at Plant Barry. Half of the capacity
     is scheduled to go in service in 2000, with the remainder going in service
     in 2001. The remaining projected expenditures related to these facilities
     are $181 million.

(iii)Cogeneration facilities, with a capacity of 200 megawatts, are being
     constructed in Theodore, Alabama, and will go in service in 2001. The
     estimated remaining costs associated with this project total $81 million.

(iv) The capital budget reflects $472 million related to projected generation
     capacity scheduled to be placed into service in 2003 and beyond.

    In addition to the above items, significant construction will continue
related to transmission and distribution facilities and the upgrading of
generating plants.

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

5.   FINANCING AND COMMITMENTS

General

To the extent possible, the Company's construction program is expected to be
financed primarily from internal sources. Short-term debt is often utilized and
the amounts available are discussed below. The Company may issue additional
long-term debt and preferred securities for debt maturities, redeeming
higher-cost securities, and meeting additional capital requirements.

Financing

The ability of the Company to finance its capital budget depends on the amount
of funds generated internally and the funds it can raise by external financing.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company has no restrictions on the
amounts of unsecured indebtedness it may incur. However, to issue additional
first mortgage bonds and preferred stock, the Company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The most restrictive of these provisions requires, for the
issuance of additional first mortgage bonds, that before-income-tax earnings, as
defined, cover pro forma annual interest charges on outstanding first mortgage
bonds at least twice; and for the issuance of additional preferred stock, that
gross income available for interest cover pro forma annual interest charges and
preferred stock dividends at least one and one-half times. The Company's
coverages are at a level that would permit any necessary amount of security
sales at current interest and dividend rates.

Bank Credit Arrangements

The Company maintains committed lines of credit in the amount of $907 million
(including $418 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$517 million expire at various times during 2000 and $390 million expire in
2004. In certain cases, such lines require payment of a commitment fee based on
the unused portion of the commitment or the maintenance of compensating balances
with the banks. Because the arrangements are based on an average balance, the



                                       II-72
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


Company does not consider any of its cash balances to be restricted as of any
specific date. Moreover, the Company borrows from time to time pursuant to
arrangements with banks for uncommitted lines of credit.

    At December 31, 1999, the Company had regulatory approval to have
outstanding up to $750 million of short-term borrowings.

Assets Subject to Lien

The Company's mortgage, as amended and supplemented, securing the first mortgage
bonds issued by the Company, constitutes a direct lien on substantially all of
the Company's fixed property and franchises.

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term obligations at December 31, 1999, were as follows:

Year                                             Commitments
----                                            ----------------
                                                (in millions)
2000                                               $  715
2001                                                  672
2002                                                  561
2003                                                  469
2004                                                  472
2005 - 2026                                         2,019
---------------------------------------------------------------
Total commitments                                  $4,908
===============================================================

Operating Leases

The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $17.8 million in 1999, $5.8 million
in 1998, and $3.0 million in 1997. At December 31, 1999, estimated minimum
rental commitments for noncancellable operating leases were as follows:

Year                                          Commitments
----                                        -----------------
                                               (in millions)
2000                                             $ 20.0
2001                                               19.6
2002                                               19.2
2003                                               18.8
2004                                               18.4
2005 - 2017                                        64.3
--------------------------------------------------------------
Total minimum payments                           $160.3
==============================================================

6.   JOINT OWNERSHIP AGREEMENTS

The Company and Georgia Power Company own equally all of the outstanding capital
stock of Southern Electric Generating Company (SEGCO), which owns electric
generating units with a total rated capacity of 1,020 megawatts, together with
associated transmission facilities. The capacity of these units is sold equally
to the Company and Georgia Power Company under a contract which, in substance,
requires payments sufficient to provide for the operating expenses, taxes,
interest expense and a return on equity, whether or not SEGCO has any capacity
and energy available. The term of the contract extends automatically for
two-year periods, subject to either party's right to cancel upon two year's
notice. The Company's share of expenses totaled $92 million in 1999, $74 million
in 1998 and $73 million in 1997, and is included in "Purchased power from
affiliates" in the Statements of Income.

    In addition, the Company has guaranteed unconditionally the obligation of
SEGCO under an installment sale agreement for the purchase of certain pollution
control facilities at SEGCO's generating units, pursuant to which $24.5 million
principal amount of pollution control revenue bonds are outstanding. Georgia
Power Company has agreed to reimburse the Company for the pro rata portion of
such obligation corresponding to its then proportionate ownership of stock of
SEGCO if the Company is called upon to make such payment under its guaranty.



                                       II-73


<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


    At December 31, 1999, the capitalization of SEGCO consisted of $50 million
of equity and $72 million of long-term debt on which the annual interest
requirement is $4.3 million. SEGCO paid dividends totaling $4.3 million in 1999,
$8.7 million in 1998, and $10.6 million in 1997, of which one-half of each was
paid to the Company. SEGCO's net income was $5.4 million, $7.5 million, and $8.5
million for 1999, 1998 and 1997, respectively.

    The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1999, follows:

                             Total
                            Megawatt        Company
    Facility (Type)         Capacity        Ownership
 ---------------------  ----------------  -------------
 Greene County                  500          60.00% (1)
    (coal)
 Plant Miller
    Units 1 and 2             1,320          91.84% (2)
    (coal)
 ----------------------------------------------------------
(1)  Jointly owned with an affiliate, Mississippi Power Company.
(2)  Jointly owned with Alabama Electric Cooperative, Inc.


                            Company          Accumulated
       Facility            Investment        Depreciation
 ---------------------    --------------    ---------------
                                    (in millions)
 Greene County               $  97              $  45
 Plant Miller
   Units 1 and 2               740                297
 ----------------------------------------------------------

7.   LONG-TERM POWER SALES AGREEMENTS

General

The Company and the operating affiliates of Southern Company have entered into
long-term contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. These
agreements -- expiring at various dates discussed below -- are firm and pertain
to capacity related to specific generating units. Because the energy is
generally sold at cost under these agreements, profitability is primarily
affected by revenues from capacity sales. The Company's capacity revenues
amounted to $122 million in 1999, $142 million in 1998, and $136 million in
1997.

    Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority
(JEA) and the City of Tallahassee, Florida. Under these agreements,
approximately 1,250 megawatts of capacity are scheduled to be sold through 2000.
Thereafter, these sales will remain at that approximate level -- unless reduced
by FP&L, FPC, and JEA for the periods after 2000 with a minimum of three years
notice -- until the expiration of the contracts in 2010.

Alabama Municipal Electric Authority (AMEA)
Capacity Contracts

In August 1986, the Company entered into a firm power sales contract with AMEA
entitling AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for
a period of 15 years commencing September 1, 1986 (1986 Contract). In October
1991, the Company entered into a second firm power sales contract with AMEA
entitling AMEA to scheduled amounts of additional capacity (to a maximum 80
megawatts) for a period of 15 years commencing October 1, 1991 (1991 Contract).
In both contracts the power will be sold to AMEA for its member municipalities
that previously were served directly by the Company as wholesale customers.
Under the terms of the contracts, the Company received payments from AMEA
representing the net present value of the revenues associated with the
respective capacity entitlements, discounted at effective annual rates of 9.96
percent and 11.19 percent for the 1986 and 1991 contracts, respectively. These
payments are being recognized as operating revenues and the discounts are being
amortized to other interest expense as scheduled capacity is made available over
the terms of the contracts.

    In order to secure AMEA's advance payments and the Company's performance
obligation under the contracts, the Company issued and delivered to an escrow
agent first mortgage bonds representing the maximum amount of liquidated damages
payable by the Company in the event of a default under the contracts. No
principal or interest is payable on such bonds unless and until a default by the
Company occurs. As the liquidated damages decline under the contracts, a portion
of the bonds equal to the decreases are returned to the Company. At December 31,
1999, $81.5 million of such bonds was held by the escrow agent under the
contracts.

8.   INCOME TAXES

At December 31, 1999, the tax-related regulatory assets and liabilities were
$330 million and $265 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable


                                       II-74

<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


to capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.

    Details of the income tax provisions are as follows:

                                      1999       1998       1997
                                 --------------------------------
                                           (in millions)
Total provision for income taxes:
Federal --
  Current                              $194       $123       $197
  Deferred --
    Current year                        (6)        59         33
    Reversal of prior years             30         13        (44)
-----------------------------------------------------------------
                                       218        195        186
-----------------------------------------------------------------
State --
  Current                               19         16         23
  Deferred --
    Current year                         1          5          1
    Reversal of prior years              4          2         (2)
-----------------------------------------------------------------
                                        24         23         22
-----------------------------------------------------------------
Total                                 $242       $218       $208
=================================================================

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

                                                   1999     1998
                                               -------------------
                                                  (in millions)
Deferred tax liabilities:
  Accelerated depreciation                      $   884   $  861
  Property basis differences                        419      435
  Fuel cost adjustment                               65       29
  Premium on reacquired debt                         31       29
  Pensions                                           60       50
  Other                                              11       17
-----------------------------------------------------------------
Total                                             1,470     1,421
-----------------------------------------------------------------
Deferred tax assets:
  Capacity prepayments                              24        28
  Other deferred costs                              25        25
  Postretirement benefits                           22        20
  Unbilled revenue                                  13        16
  Other                                             63        56
-----------------------------------------------------------------
Total                                              147       145
-----------------------------------------------------------------
Net deferred tax liabilities                     1,323     1,276
Portion included in current liabilities, net       (83)      (73)
-----------------------------------------------------------------
Accumulated deferred income taxes
    in the Balance Sheets                       $1,240    $1,203
=================================================================

    Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $11 million in 1999, 1998, and 1997. At December 31, 1999, all
investment tax credits available to reduce federal income taxes payable had been
utilized.

    A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                       1999     1998     1997
                                     --------------------------
Federal statutory rate                 35.0%    35.0%    35.0%
State income tax,
  net of federal deduction              2.4      2.5      2.4
Non-deductible book
  depreciation                          1.6      1.5      1.5
Differences in prior years'
  deferred and current tax rates       (1.3)    (1.6)    (2.3)
Other                                  (0.9)    (1.6)    (1.9)
---------------------------------------------------------------
Effective income tax rate              36.8%    35.8%    34.7%
===============================================================


                                       II-75

<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


    Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis.

9.   COMPANY OBLIGATED MANDATORILY
     REDEEMABLE PREFERRED SECURITIES

Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:

              Date of                                 Maturity
               Issue    Amount      Rate     Notes      Date
            ---------------------------------------------------
                       (millions)           (millions)
Trust I       1/1996    $ 97       7.375%     $100      3/2026
Trust II      1/1997     200       7.60        206     12/2036
Trust III     2/1999      50      Auction       52      2/2029

    Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above. In February 1999, Alabama Power Capital Trust III (Trust III), of which
the Company owns all of the common securities, issued $50 million of auction
rate mandatorily redeemable preferred securities. The distribution rate of these
variable securities was 6.42% at January 1, 2000.

    The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.

    The Trusts are subsidiaries of the Company and, accordingly, are
consolidated in the Company's financial statements.

10.  OTHER LONG-TERM DEBT

Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. The Company is required to make payments sufficient for the
authorities to meet principal and interest requirements of such bonds. With
respect to $215.9 million of such pollution control obligations, the Company has
authenticated and delivered to the trustees a like principal amount of first
mortgage bonds as security for its obligations under the installment purchase
agreements.  No principal or interest on these first mortgage bonds is payable
unless and until a default occurs on the installment purchase agreements.

   In 1997, 1998, and 1999 the Company issued unsecured senior notes. The senior
notes are, in effect, subordinated to all secured debt of the Company, including
its first mortgage bonds.

   The estimated aggregate annual maturities of capitalized lease obligations
through 2004 are as follows: $0.9 million in 2000, $0.8 million in 2001, $0.9
million in 2002, $0.9 million in 2003 and $1.0 million in 2004.

11.   SECURITIES DUE WITHIN ONE YEAR

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

                                              1999        1998
                                        ------------------------
                                              (in thousands)
  First mortgage bond maturities
     and redemptions                      $100,000    $470,000
  Other long-term debt maturities
     (Note 10)                                 943       1,209
  -------------------------------------------------------------
  Total long-term debt due within
     one year                              100,943     471,209
  -------------------------------------------------------------
  Preferred stock to be redeemed                 -      50,000
  -------------------------------------------------------------
  Total                                   $100,943    $521,209
  =============================================================

      The annual first mortgage bond improvement fund requirement is 1 percent
of the aggregate principal amount of bonds of each series authenticated, so long
as a portion of that series is outstanding, and may be satisfied by the deposit
of cash and/or reacquired bonds, the certification of unfunded property
additions or a combination thereof.

12.   NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act of 1988 (the Act), the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at Plant
Farley. The Act provides funds up to $9.5 billion for public liability claims


                                       II-76
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report


that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $200 million by private insurance, with the
remaining coverage provided by a mandatory program of deferred premiums which
could be assessed, after a nuclear incident, against all owners of nuclear
reactors. The Company could be assessed up to $88 million per incident for each
licensed reactor it operates but not more than an aggregate of $10 million per
incident to be paid in a calendar year for each reactor. Such maximum
assessment, excluding any applicable state premium taxes, for the Company is
$176 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year.

    The Company is a member of Nuclear Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.

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

    NEIL also covers the additional cost that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can be insured against increased costs of replacement power in an
amount up to $3.5 million per week (starting 12 weeks after the outage) for one
year and up to $2.8 million per week for the second and third years.

    Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $19 million.

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

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

13.   COMMON STOCK DIVIDEND
      RESTRICTIONS

The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 1999, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.

14.   QUARTERLY FINANCIAL INFORMATION
      (Unaudited)

Summarized quarterly financial data for 1999 and 1998 are as follows:

                                                       Net Income
                                                         After
                                                       Dividends
       Quarter            Operating      Operating    on Preferred
        Ended              Revenues        Income        Stock
--------------------    --------------------------------------------
                                     (in millions)

March 1999                  $  714           $162         $ 63
June 1999                      823            209           93
September 1999               1,116            388          201
December 1999                  733            136           43

March 1998                  $  717           $173         $ 66
June 1998                      864            235           95
September 1998               1,058            342          174
December 1998                  748            132           42
-----------------------------------------------------------------

The Company's business is influenced by seasonal weather conditions.

                                       II-77



<PAGE>
<TABLE>
<CAPTION>

SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Alabama Power Company 1999 Annual Report

----------------------------------------------------------------------------------------------------------------------------------
                                                              1999            1998            1997            1996           1995
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>             <C>             <C>             <C>            <C>
Operating Revenues (in thousands)                       $3,385,474      $3,386,373      $3,149,111      $3,120,775     $3,024,774
Net Income after Dividends
  on Preferred Stock (in thousands)                       $399,880        $377,223        $375,939        $371,490       $360,894
Cash Dividends
  on Common Stock (in thousands)                          $399,600        $367,100        $339,600        $347,500       $285,000
Return on Average Common Equity (percent)                    13.85           13.63           13.76           13.75          13.61
Total Assets (in thousands)                             $9,648,704      $9,225,698      $8,812,867      $8,733,846     $8,744,360
Gross Property Additions (in thousands)                   $809,044        $610,132        $451,167        $425,024       $551,781
----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                     $2,988,863      $2,784,067      $2,750,569      $2,714,277     $2,690,374
Preferred stock                                            317,512         317,512         255,512         340,400        440,400
Company obligated mandatorily
  redeemable preferred securities                          347,000         297,000         297,000          97,000              -
Long-term debt                                           3,190,378       2,646,566       2,473,202       2,354,006      2,374,948
----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)           $6,843,753      $6,045,145      $5,776,283      $5,505,683     $5,505,722
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                           43.7            46.1            47.6            49.3           48.9
Preferred stock                                                4.6             5.3             4.4             6.2            8.0
Company obligated mandatorily
  redeemable preferred securities                              5.1             4.9             5.2             1.7              -
Long-term debt                                                46.6            43.7            42.8            42.8           43.1
----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)                100.0           100.0           100.0           100.0          100.0
==================================================================================================================================
Security Ratings:
First Mortgage Bonds -
    Moody's                                                     A1              A1              A1              A1             A1
    Standard and Poor's                                         A+              A+              A+              A+             A+
    Duff & Phelps                                               AA-             AA-             AA-             AA-             A+
Preferred Stock -
    Moody's                                                     a2              a2              a2              a2             a2
    Standard and Poor's                                         A-               A               A               A              A
    Duff & Phelps                                                A               A              A+              A+              A
Unsecured Long-Term Debt -
    Moody's                                                     A2              A2              A2               -              -
    Standard and Poor's                                          A               A               A               -              -
    Duff & Phelps                                               A+              A+              A+               -              -
==================================================================================================================================
Customers (year-end):
Residential                                              1,120,574       1,106,217       1,092,161       1,073,559      1,058,197
Commercial                                                 188,368         182,738         177,362         171,827        166,480
Industrial                                                   4,897           5,020           5,076           5,100          5,338
Other                                                          735             733             728             732            725
----------------------------------------------------------------------------------------------------------------------------------
Total                                                    1,314,574       1,294,708       1,275,327       1,251,218      1,230,740
==================================================================================================================================
Employees (year-end):                                        6,792           6,631           6,531           6,865          7,261
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>






                                                                  II-78


<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Alabama Power Company 1999 Annual Report

---------------------------------------------------------------------------------------------------------------------------------
                                                             1999            1998            1997            1996           1995
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>              <C>              <C>             <C>            <C>
Operating Revenues (in thousands):
Residential                                           $ 1,145,646      $1,133,435       $ 997,507       $ 998,806      $ 997,069
Commercial                                                807,098         779,169         724,148         696,453        670,453
Industrial                                                843,090         853,550         775,591         759,628        805,596
Other                                                      15,283          14,523          13,563          13,729         13,619
---------------------------------------------------------------------------------------------------------------------------------
Total retail                                            2,811,117       2,780,677       2,510,809       2,468,616      2,486,737
Sales for resale  - non-affiliates                        415,377         448,973         431,023         391,669        370,140
Sales for resale  - affiliates                             92,439         103,562         161,795         216,620        127,730
---------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity                3,318,933       3,333,212       3,103,627       3,076,905      2,984,607
Other revenues                                             66,541          53,161          45,484          43,870         40,167
---------------------------------------------------------------------------------------------------------------------------------
Total                                                  $3,385,474      $3,386,373      $3,149,111      $3,120,775     $3,024,774
=================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential                                            15,699,081      15,794,543      14,336,408      14,593,761     14,383,231
Commercial                                             12,314,085      11,904,509      11,330,312      10,904,476     10,043,220
Industrial                                             21,942,889      21,585,117      20,727,912      19,999,258     19,862,577
Other                                                     201,149         196,647         180,389         192,573        186,848
---------------------------------------------------------------------------------------------------------------------------------
Total retail                                           50,157,204      49,480,816      46,575,021      45,690,068     44,475,876
Sales for resale  - non-affiliates                     12,437,599      11,840,910      12,329,480       9,491,237      8,046,189
Sales for resale  - affiliates                          5,031,781       5,976,099       8,993,326      10,292,066      6,705,174
---------------------------------------------------------------------------------------------------------------------------------
Total                                                  67,626,584      67,297,825      67,897,827      65,473,371     59,227,239
=================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                                  7.30            7.18            6.96            6.84           6.93
Commercial                                                   6.55            6.55            6.39            6.39           6.68
Industrial                                                   3.84            3.95            3.74            3.80           4.06
Total retail                                                 5.60            5.62            5.39            5.40           5.59
Sales for resale                                             2.91            3.10            2.78            3.07           3.38
Total sales                                                  4.91            4.95            4.57            4.70           5.04
Residential Average Annual
  Kilowatt-Hour Use Per Customer                           14,097          14,370          13,254          13,705         13,686
Residential Average Annual
  Revenue Per Customer                                  $1,028.76       $1,031.21         $922.21         $937.95        $948.71
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                           11,151          11,151          11,151          11,151         10,831
Maximum Peak-Hour Demand (megawatts):
Winter                                                      8,863           7,757           8,478           8,413          7,958
Summer                                                     10,739          10,329           9,778           9,912         10,090
Annual Load Factor (percent)                                 59.7            62.9            62.7            61.3           59.2
Plant Availability (percent):
Fossil-steam                                                 80.4            85.6            86.3            86.6           88.3
Nuclear                                                      91.0            80.2            88.8            90.5           81.1
---------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                         64.1            65.3            65.7            67.0           67.1
Nuclear                                                      17.8            16.3            17.9            18.5           17.1
Hydro                                                         4.7             6.9             7.5             7.1            7.0
Oil and gas                                                   1.1             1.5             0.7             0.4            0.4
Purchased power -
  From non-affiliates                                         4.5             3.3             2.4             2.4            2.7
  From affiliates                                             7.8             6.7             5.8             4.6            5.7
---------------------------------------------------------------------------------------------------------------------------------
Total                                                       100.0           100.0           100.0           100.0          100.0
=================================================================================================================================
</TABLE>


                                                                  II-79

<PAGE>
                             GEORGIA POWER COMPANY

                               FINANCIAL SECTION




                                     II-80

<PAGE>

MANAGEMENT'S REPORT
Georgia Power Company 1999 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 generally accepted accounting
principles appropriate in the circumstances, and necessarily include amounts
that are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.

    The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls 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
directors who are not employees, 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 generally accepted accounting
principles.




/s/David M. Ratcliffe
David M. Ratcliffe
President and Chief
 Executive Officer

/s/Thomas A. Fanning
Thomas A. Fanning
Executive Vice President,
 Treasurer and Chief
 Financial Officer



February 16, 2000



                                      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, 1999 and 1998, and the related statements
of income, common stockholders' equity, and cash flows for each of the three
years in the period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

    In our opinion, the financial statements (pages 11-91 through 11-110)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1999 and 1998, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.


/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000





                                       II-82
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1999 Annual Report


RESULTS OF OPERATIONS

Earnings

Georgia Power Company's 1999 earnings totaled $541 million, representing a $29
million (5.1 percent) decrease from 1998. This earnings decrease is primarily
due to the recognition of interest income in 1998 as a result of the resolution
of tax issues with the Internal Revenue Service (IRS). Earnings from normal
operations increased due primarily to lower accelerated depreciation under the
1998 Georgia Public Service Commission (GPSC) rate order, sales growth and
decreased financing costs, partially offset by retail rate reductions under the
new order and lower wholesale revenues. Earnings for 1998 totaled $570 million,
representing a $24 million (4.0 percent) decrease from 1997. This earnings
decrease resulted primarily from higher operating expenses, accelerated
depreciation charges pursuant to a previous GPSC retail accounting order ending
December 1998, lower wholesale revenues, and the write-off of a portion of the
Rocky Mountain plant investment. These decreases to earnings were partially
offset by higher retail revenues, lower financing costs and the effect of the
IRS settlement.

Revenues

The following table summarizes the factors impacting operating revenues for the
1997-1999 period:

                                          Increase (Decrease)
                                            From Prior Year
                                    --------------------------------
                                       1999       1998        1997
                                    --------------------------------
Retail -                                     (in millions)
   1998 GPSC rate order              $(262)      $   -      $    -
   Revenue subject to refund           (79)          -           -
   Sales growth                        102         174          62
   Weather                             (53)        101         (74)
   Fuel cost recovery and other         44          45         (33)
--------------------------------------------------------------------
Total retail                          (248)        320         (45)
--------------------------------------------------------------------
Sales for resale -
   Non-affiliates                      (49)        (23)          1
   Affiliates                           (5)         43           3
--------------------------------------------------------------------
Total sales for resale                 (54)         20           4
--------------------------------------------------------------------
Other operating revenues                21          13          10
--------------------------------------------------------------------
Total operating revenues             $(281)      $ 353      $  (31)
====================================================================
Percent change                        (5.9)%       8.0%      (0.7)%
--------------------------------------------------------------------

    Retail revenues of $4.1 billion in 1999 decreased $248 million (5.8 percent)
primarily due to retail rate reductions under the 1998 GPSC rate order. Pursuant
to the order, in 1999 the Company also recorded $79 million of revenue subject
to refund for estimated earnings above 12.5 percent retail return on common
equity. Refunds will be made to customers in 2000. See Note 3 to the financial
statements under "Retail Rate Orders" for additional information. Retail
revenues of $4.3 billion in 1998 increased $320 million (8.0 percent) from 1997
primarily due to higher energy sales to residential and commercial customers.

    Fuel revenues generally represent the direct recovery of fuel expense,
including the fuel component of purchased energy, and do not affect net income.

    Wholesale revenues from sales to non-affiliated utilities decreased in 1999
and 1998 and were as follows:

                                  1999       1998      1997
                                -------------------------------
                                        (in millions)
Outside service area -

   Long-term contracts           $  55      $  51     $  71
   Other sales                      74         93        79
Inside service area                 81        115       132
---------------------------------------------------------------
Total                            $ 210      $ 259     $ 282
===============================================================

    Revenues from long-term contracts outside the service area increased
slightly in 1999 due to increased energy sales and decreased in 1998 primarily
due to lower capacity charges and decreased energy sales. See Note 7 to the
financial statements for further information regarding these sales. Revenues
from other sales outside the service area decreased in 1999 and increased in
1998 primarily due to the effect of power marketing activities and were
generally offset by a corresponding decrease and increase, respectively, in
purchased power from non-affiliates. Wholesale revenues from customers within
the service area decreased in 1999 and 1998 primarily due to a decrease in
revenues under a power supply agreement with Oglethorpe Power Corporation (OPC).

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



                                       II-83


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report


    Other operating revenues increased $21 million (21 percent) primarily due to
increased revenues from equipment rentals. In 1998, other operating revenues
increased $13 million (14.9 percent) primarily due to increased revenues from
the transmission of electricity.

    Kilowatt-hour (KWH) sales for 1999 and the percent change by year were as
follows:

                                            Percent Change
                                      ----------------------------
                            1999
                             KWH       1999      1998      1997
                         --------- -----------------------------
                           (in billions)

Residential                   19.4     (0.4)%    12.6%     (3.0)%
Commercial                    23.7      3.7       8.2       1.5
Industrial                    27.3      0.1       2.2       1.9
Other                          0.6      1.5       1.0       0.4
                            --------
Total retail                  71.0      1.1       6.9       0.4
                            --------
Sales for resale -
   Non-affiliates              5.0   (21.4)      (5.2)    (13.6)
   Affiliates                  1.8   (11.9)      19.4      44.6
                            --------
Total sales for resale         6.8   (19.1)      (0.3)     (6.0)
                            --------
Total sales                   77.8    (1.0)       6.0      (0.3)
                            ========

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

    Residential sales decreased 0.4 percent in 1999 due to moderate summer
temperatures, while commercial sales increased 3.7 percent due to strong
regional economic growth. Industrial sales remained fairly constant. Residential
and commercial sales increased in 1998 12.6 percent and 8.2 percent,
respectively, and industrial sales increased slightly by 2.2 percent. The
increases are attributed primarily to sales growth and hotter temperatures in
the summer months.

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:

                                        1999     1998     1997
                                      -------------------------
Total generation
   (billions of KWH)                    69.3     69.1     66.5
Sources of generation
   (percent) --
     Coal                               75.5     73.3     74.8
     Nuclear                            21.6     21.6     21.8
     Hydro                               1.0      2.6      2.7
     Oil and gas                         1.9      2.5      0.7
Average cost of fuel per net
   KWH generated
     (cents) --                         1.34     1.36     1.32
---------------------------------------------------------------

    Fuel expense increased 0.3 percent in 1999 due to a slight increase in
generation, partially offset by a lower average cost of fuel. Fuel expense
increased 7.0 percent in 1998 primarily due to an increase in generation to meet
higher energy demands and a higher average cost of fuel.

    Purchased power expense decreased slightly in 1999. Purchased power expense
in 1998 increased $70 million (21.9 percent) over the prior year primarily due
to higher energy demands and power marketing activities. As discussed earlier,
the expense associated with energy purchased for power marketing activities is
generally offset by revenue when resold to non-affiliates.

    Other operation and maintenance expenses increased 1.6 percent in 1999
primarily due to increased generating plant maintenance, partially offset by a
reduction in the charges related to the implementation of a customer service
system in 1998, decreased year 2000 readiness costs, and decreased employee
benefit provisions. Other operation and maintenance expenses increased 15.5
percent in 1998 primarily due to expenses related to the customer service system
discussed above, modification of certain information systems for year 2000
compliance discussed below, an increase in outage costs at generating
facilities, and increased line maintenance.



                                      II-84

<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report


    Depreciation and amortization decreased $346 million in 1999 primarily due
to higher depreciation charges recognized in 1998 under the prior GPSC
accounting order and the completion in 1998 of the amortization of deferred
Plant Vogtle costs. Depreciation and amortization increased $121 million in 1998
primarily due to accelerated depreciation of generating plant pursuant to the
previous retail accounting order and an increase in plant-in-service. See Note 3
to the financial statements under "Retail Rate Orders" for additional
information.

    As a result of the 1998 retail rate order, the Company recorded a $34
million pre-tax write-off associated with a portion of its investment in the
Rocky Mountain plant in 1998. See Note 3 to the financial statements under
"Rocky Mountain Status" for additional information.

    Interest income decreased in 1999 primarily due to the 1998 recognition of
$73 million in interest income resulting from the resolution of tax issues with
the IRS and the State of Georgia. Other, net decreased in 1999 due primarily to
increased bad debt expense related to consumer energy efficiency improvement
financing.

    Financing costs decreased in 1999 and 1998. These changes were primarily due
to the refinancing or retirement of securities. The Company refinanced or
retired $775 million and $754 million of securities in 1999 and 1998,
respectively. Dividends on preferred stock decreased $4 million and $13 million
in 1999 and 1998, respectively. Pursuant to the new three-year retail rate order
which the Company began operating under on January 1, 1999, the Company recorded
$85 million in accelerated amortization of premium on reacquired debt. Other
interest charges decreased $12 million in 1999 primarily due to the recognition
in 1998 of interest related to tax issues. Distributions on preferred securities
of subsidiary companies increased $11 million and $7 million in 1999 and 1998,
respectively, primarily due to the issuance of additional mandatorily redeemable
preferred securities in 1999 and 1997.

Effects of Inflation

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


FUTURE EARNINGS POTENTIAL

The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including regulatory matters and energy sales.

    The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
State of Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC under cost-based regulatory principles.

    On January 1, 1999, the Company began operating under a new three-year
retail rate order. The Company's earnings will continue to be evaluated against
a retail return on common equity range of 10 percent to 12.5 percent, with rate
reductions of $262 million in 1999 and an additional reduction of $24 million in
2000. The order provides for $85 million in each year, plus up to $50 million of
any earnings above the 12.5 percent return during the second and third years, to
be applied to accelerated amortization or depreciation of assets. Two-thirds of
any additional earnings above the 12.5 percent return will be applied to rate
reductions, with the remaining one-third retained by the Company. Pursuant to
the order, in 1999 the Company recorded $85 million in accelerated amortization
of premium on reacquired debt. The Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent. Refunds will be
made to customers in 2000. The Company will not file for a general base rate
increase unless its projected retail return on common equity falls below 10
percent, and will be required to file a general rate case on July 1, 2001 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.


                                      II-85


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report


    Growth in energy sales is subject to a number of factors which traditionally
have included changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, weather,
competition, initiatives to increase sales to existing customers, and the rate
of economic growth in the Company's service area. Assuming normal weather,
retail sales growth from 1999 is projected to be approximately 2.9 percent
annually on average during 2000 through 2002.

    The Company has entered into two purchase power agreements scheduled to
begin after 1999. The first agreement is for five years and will begin in June
2000. The agreement is for approximately 215 megawatts, and capacity payments
are estimated to be between $7 million and $8 million each year. The second
agreement is for seven years and will begin in June 2002. The agreement is for
approximately 310 megawatts during the first three years and approximately 465
megawatts during the remaining four years. Capacity payments are estimated to be
between $16 million and $17 million in each of the first three years and then
between $23 million and $24 million in each of the last four years of the
contract.

    The Company is constructing a ten unit, 800 megawatt combustion turbine
peaking power plant that will serve the wholesale market. Units one through
eight will begin operation in 2000; units nine and ten will begin operation in
2001. The Company also plans to construct a 570 megawatt combined cycle unit
that will begin operation in 2002 and will also serve the wholesale market. The
Company has entered into wholesale contracts to sell 560 megawatts of the new
capacity. The Company is also planning to construct two 568 megawatt combined
cycle units at Plant Wansley, to begin operation in 2002. The Company has
applied to the GPSC for certification of these units to serve retail customers.
Savannah Electric (also a wholly-owned subsidiary of Southern Company) will
purchase 200 megawatts of capacity from these units. See Note 4 to the financial
statements under "Construction Program" for additional information.

    Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. See "Environmental Issues" for further discussion of these matters.

    The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. The Company is aggressively working to maintain and expand its
share of wholesale sales in the Southeastern power markets. Although the Energy
Act does not permit retail customer access, it was a major catalyst for the
current restructuring and consolidation taking place within the utility
industry.

    On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including the Company, are required to
make a filing by October 15, 2000. The filing must contain either a proposal for
RTO participation or a description of the efforts made to participate in an RTO,
the reasons for non-participation, any obstacles to participation, and any plans
for further work toward participation. The RTOs that are proposed in the filings
should be operational by December 15, 2001. The Company is evaluating the issue
and the outcome cannot now be determined.

    The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with at least 900 kilowatts of
connected load may choose their electricity supplier. Numerous federal and state
initiatives are in varying stages to promote wholesale and retail competition
across the nation. Among other things, these initiatives allow customers to
choose their electricity provider. As these initiatives materialize, the
structure of the utility industry could radically change. Some states have
approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While the GPSC has held workshops to
discuss retail competition and industry restructuring, there has been no
proposed or enacted legislation to date in Georgia. Enactment would require
numerous issues to be resolved, including significant ones relating to


                                       II-86

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report


transmission pricing and recovery of costs. The GPSC plans to release a report
on an initial assessment of the range of potential stranded costs in 2000. The
inability of the Company to recover all its costs, including the regulatory
assets described in Note 1 to the financial statements, could have a material
effect on the financial condition of the Company. The Company is attempting to
reduce regulatory assets and other costs through the three-year retail rate
order. See Note 3 to the financial statements under "Retail Rate Orders" for
additional information.

    Unless the Company remains a low-cost producer and provides quality service,
the Company's retail energy sales growth could be limited as competition
increases. Conversely, continuing to be a low-cost producer could provide
opportunities to increase market share and profitability in markets that evolve
with changing 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.

    The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry - including
the Company's - regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating facilities in the financial
statements. In response to these questions, the FASB has decided to review the
accounting for liabilities related to the retirement of long-lived assets,
including nuclear decommissioning. If the FASB issues new accounting rules, the
estimated costs of retiring the Company's nuclear and other facilities may be
required to be recorded as liabilities in the Balance Sheets. Also, the annual
provisions for such costs could change. Because of the Company's current ability
to recover asset retirement costs through rates, these changes would not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.

Year 2000 Challenge

The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.

    For the Company, original projected total costs for Year 2000 readiness,
including the Company's share of costs of Southern Nuclear Operating Company,
were approximately $38 million. These costs include labor necessary to identify,
test, and renovate affected devices and systems, and costs for reporting
requirements to state and federal agencies. From its inception through December
31, 1999, the Year 2000 program costs, recognized as expense, amounted to $41
million. An additional $2 million is projected to be spent in 2000.

Exposure to Market Risks

Due to cost-based rate regulation, the Company currently has limited exposure to
market volatility in interest rates and prices of electricity. See the
discussion above for potential changes in industry structure. To mitigate
residual risks relative to movements in electricity prices, the Company enters
into fixed price contracts for the purchase and sale of electricity through the
wholesale electricity market. Realized gains and losses are recognized in the
income statement as incurred. At December 31, 1999, exposure from these
activities was not material to the Company's financial position, results of
operations, or cash flows. Also, based on the Company's overall interest rate
exposure at December 31, 1999, a near-term 100 basis point change in interest
rates would not materially affect the financial statements.

New Accounting Standard

The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 2001. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for

                                       II-87

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report


hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.

FINANCIAL CONDITION

Plant Additions

In 1999 gross utility plant additions were $790 million. 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 or long-term debt, and from equity from
Southern. The Statements of Cash Flows provide additional details.

Financing Activities

In 1999 the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1997 through 1999 totaled $1.8 billion and
retirement or repayment of securities totaled $2.2 billion.

    Special purpose subsidiaries of the Company have issued mandatorily
redeemable preferred securities. See Note 9 to the financial statements under
"Preferred Securities" for additional information.

    Composite financing rates for long-term debt, preferred stock and preferred
securities for the years 1997 through 1999, as of year-end, were as follows:

                                   1999        1998        1997
                                ----------------------------------
Composite interest rate
   on long-term debt               5.48%       5.64%       6.11%
Composite preferred
   stock dividend rate             4.60        5.52        5.18
Composite preferred
   securities dividend rate        7.49        7.89        7.89
------------------------------------------------------------------

Liquidity and Capital Requirements

Cash provided from operations decreased by $206 million in 1999, primarily due
to lower retail revenues.

    The Company estimates that construction expenditures for the years 2000
through 2002 will total $1.2 billion, $1.5 billion and $1.5 billion,
respectively. Investments in additional combustion turbine and combined cycle
generating units, transmission and distribution facilities, enhancements to
existing generating plants, and equipment to comply with environmental
requirements are planned.

    Cash requirements for improvement fund requirements, redemptions announced,
and maturities of long-term debt are expected to total $168 million during 2000
through 2002.

    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 is $30 million each year in 2000,
2001 and 2002. 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 and, if needed, by the
issuance of new debt and equity securities, term loans, and short-term
borrowings. To meet short-term cash needs and contingencies, the Company had
approximately $1.3 billion of unused credit arrangements with banks at the
beginning of 2000. See Note 9 to the financial statements under "Bank Credit
Arrangements" for additional information.

    The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have also consisted of
unsecured debt and trust preferred securities. In this regard, the Company



                                       II-88
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report


sought and obtained stockholder approval in 1997 to amend its corporate charter
eliminating restrictions on the amounts of unsecured indebtedness it may incur.

    If the Company chooses to issue first mortgage bonds or preferred stock, it
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.

ENVIRONMENTAL ISSUES

Clean Air Act

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
impacted the operating companies of Southern Company, including Georgia Power.
Specific reductions in sulfur dioxide and nitrogen oxide emissions from
fossil-fired generating plants are required in two phases. Phase I compliance
began in 1995 and initially affected 28 generating units in the Southern
electric system. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants in the Southern electric system are affected.

    Southern Company achieved Phase I sulfur dioxide compliance at the affected
units by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Georgia Power's Phase I compliance totaled
approximately $167 million.

    For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. 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 by $38
million.

    The State of Georgia submitted a plan for nitrogen oxide emission reductions
in Atlanta's ozone non-attainment area on October 29, 1999. The Environmental
Protection Agency (EPA) found this plan to be deficient and required the State
to address the shortfalls of the plan. Based on the revised plan approved by the
Georgia Department of Natural Resources on January 26, 2000, the Company
estimates its capital expenditures to comply with the plan to be approximately
$713 million through 2003, of which $705 million remains to be spent. It is
still uncertain at this time what additional controls may be required at the
Company's plants beyond the recently submitted plan.

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

Environmental Protection Agency Litigation

On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. The civil action requests penalties and injunctive
relief, including an order requiring the installation of the best available
control technology at the affected units. The EPA concurrently issued a notice
of violation to the Company relating to these two plants. In early 2000, the
EPA filed a motion to amend its complaint to add the violations alleged in its
notice of violation.  The complaint and the notice of violation are similar to
those brought against and issued to several other electric utilities. The
complaint and the notice of violation allege that the Company failed to secure
necessary permits or install additional pollution equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. The Company believes that it complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows and possibly financial condition
unless such costs can be recovered through regulated rates.

                                       II-89

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report


Other Environmental Issues

In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision makes the standards significantly
more stringent. In September 1998, the EPA issued the final regional nitrogen
oxide rule to the states for implementation. The final rule affects 22 states
including Georgia. The EPA's July 1997 standards and the September 1998 rule are
being challenged in the courts by several states and industry groups.
Implementation of the final state rules for these three initiatives could
require substantial further reductions in nitrogen oxide and sulfur dioxide
emissions from fossil-fired generating facilities and other industries in these
states. Additional compliance costs and capital expenditures resulting from the
implementation of these rules and standards cannot be determined until the
results of legal challenges are known, and the states have adopted their final
rules.

    The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. The Company conducts studies to determine the extent of any
required clean-up costs and has recognized in the financial statements costs to
clean up known sites. These costs for the Company amounted to $4 million, $6
million and $4 million in 1999, 1998 and 1997, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion of or all required clean-up costs. See Note 3 to the financial
statements under "Other Environmental Contingencies" for information regarding
the Company's potentially responsible party status at a site in Brunswick,
Georgia, and the status of sites listed on the State of Georgia's hazardous site
inventory.

    The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: nitrogen oxide emission control strategies
for ozone non-attainment areas; additional controls for hazardous air pollutant
emissions; control strategies to reduce regional haze; and hazardous waste
disposal requirements. The impact of any new standards will depend on the
development and implementation of applicable regulations.

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

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


CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION

The Company's 1999 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information. Accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the Company's markets; potential business strategies -- including
acquisitions or dispositions of assets or internal restructuring -- that may be
pursued by Southern Company; state and federal rate regulation; changes in or
application of environmental and other laws and regulations to which the Company
is subject; political, legal and economic conditions and developments; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; and other
factors discussed in the reports--including Form 10-K--filed from time to time
by the Company with the Securities and Exchange Commission.


                                     II-90

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, 1997
Georgia Power Company 1999 Annual Report

---------------------------------------------------------------------------------------------------------------------------
                                                                              1999                 1998                1997
---------------------------------------------------------------------------------------------------------------------------
                                                                                             (in thousands)

<S>                                                                     <C>                  <C>                 <C>
Operating Revenues:
Retail sales                                                            $4,050,088           $4,298,217          $3,978,299
Sales for resale --
  Non-affiliates                                                           210,104              259,234             282,365
  Affiliates                                                                76,426               81,606              38,708
Other revenues                                                             120,057               99,196              86,345
----------------------------------------------------------------------------------------------------------------------------
Total operating revenues                                                 4,456,675            4,738,253           4,385,717
----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                                     919,876              917,119             857,269
  Purchased power --
    Non-affiliates                                                         214,573              229,960             143,409
    Affiliates                                                             174,989              161,003             177,240
  Other                                                                    784,359              819,589             702,159
Maintenance                                                                411,983              358,218             317,199
Depreciation and amortization                                              467,966              813,802             693,217
Taxes other than income taxes                                              202,853              204,623             207,192
Write down of Rocky Mountain plant                                               -               33,536                   -
----------------------------------------------------------------------------------------------------------------------------
Total operating expenses                                                 3,176,599            3,537,850           3,097,685
----------------------------------------------------------------------------------------------------------------------------
Operating Income                                                         1,280,076            1,200,403           1,288,032
Other Income (Expense):
Interest income                                                              5,583               79,578              10,581
Equity in earnings of unconsolidated subsidiaries                            2,721                3,735               4,266
Other, net                                                                 (47,986)             (38,277)            (29,822)
----------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                                1,240,394            1,245,439           1,273,057
----------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt                                                 162,303              180,746             194,344
Interest on notes payable                                                   19,787               12,213               7,795
Amortization of debt discount, premium and expense, net (Note 3)           100,115               13,366              14,179
Other interest charges, net                                                 (2,336)               9,988               1,292
Distributions on preferred securities of subsidiary                         65,774               54,327              47,369
----------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                                      345,643              270,640             264,979
----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                               894,751              974,799           1,008,078
Income taxes                                                               351,639              398,632             395,155
----------------------------------------------------------------------------------------------------------------------------
Net Income                                                                 543,112              576,167             612,923
Dividends on Preferred Stock                                                 1,729                5,939              18,927
----------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock                            $ 541,383            $ 570,228           $ 593,996
============================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>


                                                                  II-91

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Georgia Power Company 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------------
                                                                           1999                  1998                  1997
                                                                                             (in thousands)
<S>                                                                   <C>                   <C>                   <C>
Operating Activities:
Net income                                                            $ 543,112             $ 576,167             $ 612,923
Adjustments to reconcile net income to net
  cash provided from operating activities --
      Depreciation and amortization                                     578,878               867,637               674,286
      Deferred income taxes and investment tax credits, net             (34,930)              (93,005)              (21,425)
      Allowance for equity funds used during construction                  (734)               (3,235)               (6,012)
      Amortization of deferred Plant Vogtle costs                             -                50,412               120,577
      Other, net                                                         43,555                (6,781)                1,991
      Changes in certain current assets and liabilities --
         Receivables, net                                                21,665               (25,453)               13,387
         Inventories                                                    (32,582)              (11,156)               39,748
         Payables                                                        13,095                47,862               (10,007)
         Taxes accrued                                                   (2,832)               22,139                (3,596)
         Energy cost recovery, retail                                   (26,862)               (7,649)              (20,103)
         Other                                                           93,620               (15,142)              (30,026)
----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                           1,195,985             1,401,796             1,371,743
----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                               (790,464)             (499,053)             (475,921)
Other                                                                   (27,454)               67,031                16,223
----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                 (817,918)             (432,022)             (459,698)
----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                               295,389               (25,378)              (64,266)
Proceeds --
  Senior notes                                                          100,000               495,000                     -
  Pollution control bonds                                               238,000                89,990               284,700
  Preferred securities                                                  200,000                     -               364,250
  Capital contributions from parent company                             155,777                   235                    85
Retirements --
  First mortgage bonds                                                 (404,000)             (558,250)              (60,258)
  Pollution control bonds                                              (235,000)              (89,990)             (284,700)
  Preferred securities                                                 (100,000)                    -                     -
  Preferred stock                                                       (36,231)             (106,064)             (356,392)
Capital distributions to parent company                                       -              (270,000)             (205,000)
Special deposits -- redemption funds                                          -                     -                44,454
Payment of preferred stock dividends                                       (984)               (9,137)              (26,917)
Payment of common stock dividends                                      (543,000)             (536,600)             (520,000)
Other                                                                   (29,630)              (26,641)              (20,024)
----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities                                 (359,679)           (1,036,835)             (844,068)
----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                  18,388               (67,061)               67,977
----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year                           16,272                83,333                15,356
----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                $34,660               $16,272               $83,333
----------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
  Interest (net of amount capitalized)                                $ 247,050             $ 269,524             $ 258,298
  Income taxes (net of refunds)                                         394,457               480,318               427,596
--------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-92



<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------------
Assets                                                                                     1999                     1999
--------------------------------------------------------------------------------------------------------------------------
                                                                                                  (in thousands)

<S>                                                                                    <C>                      <C>
Current Assets:
Cash and cash equivalents                                                           $    34,660              $    16,272
Receivables --
  Customer accounts receivable                                                          438,161                  439,420
  Other accounts and notes receivable                                                   102,544                   99,574
  Affiliated companies                                                                   16,006                   16,817
  ccumulated provision for uncollectible accounts                                        (7,000)                  (5,500)
Fossil fuel stock, at average cost                                                      126,298                  104,133
Materials and supplies, at average cost                                                 253,894                  243,477
Other                                                                                    63,990                   73,280
-------------------------------------------------------------------------------------------------------------------------
Total current assets                                                                  1,028,553                  987,473
-------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service                                                                           15,798,624               15,441,146
Less accumulated provision for depreciation                                           6,538,574                6,109,331
-------------------------------------------------------------------------------------------------------------------------
                                                                                      9,260,050                9,331,815
Nuclear fuel, at amortized cost                                                         119,288                  121,169
Construction work in progress (Note 4)                                                  425,975                  189,849
-------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                                  9,805,313                9,642,833
-------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4)                               25,024                   24,360
Nuclear decommissioning trusts                                                          371,914                  284,536
Other                                                                                    33,766                   34,781
-------------------------------------------------------------------------------------------------------------------------
Total other property and investments                                                    430,704                  343,677
-------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8)                                       590,893                  604,488
Prepaid pension costs                                                                   145,801                  103,606
Debt expense, being amortized                                                            55,824                   51,261
Premium on reacquired debt, being amortized                                              99,331                  173,858
Other                                                                                   120,441                  126,422
-------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                               1,012,290                1,059,635
-------------------------------------------------------------------------------------------------------------------------
Total Assets                                                                        $12,276,860              $12,033,618
=========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>



                                                                  II-93




<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report

---------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                                               1999                     1998
---------------------------------------------------------------------------------------------------------------------------------
                                                                                                          (in thousands)

<S>                                                                                        <C>                      <C>
Current Liabilities:
Securities due within one year (Note 9)                                                     $   155,772              $   435,085
Notes payable                                                                                   636,241                  340,852
Accounts payable --
  Affiliated                                                                                     76,591                   75,774
  Other                                                                                         346,785                  326,317
Customer deposits                                                                                74,695                   69,584
Taxes accrued --
  Income taxes                                                                                    7,914                   15,801
  Other                                                                                         127,414                  122,359
Interest accrued                                                                                 58,665                   60,187
Vacation pay accrued                                                                             38,143                   34,443
Other                                                                                           153,767                   66,350
---------------------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                                     1,675,987                1,546,752
---------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (See accompanying statements)                                                  2,688,358                2,744,362
---------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8)                                                    2,202,565                2,249,613
Deferred credits related to income taxes (Note 8)                                               267,083                  284,017
Accumulated deferred investment tax credits (Note 8)                                            367,114                  381,914
Employee benefits provisions                                                                    181,529                  177,148
Other                                                                                           151,812                  160,863
---------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                                  3,170,103                3,253,555
---------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily Redeemable Preferred
  Securities Of Subsidiary Trusts Holding Company Junior
  Subordinated Notes (See accompanying statements)                                              789,250                  689,250
---------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock (See accompanying statements)                                         14,952                   15,527
---------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (See accompanying statements)                                     3,938,210                3,784,172
---------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                                  $12,276,860              $12,033,618
=================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>



                                                                  II-94




<PAGE>


<TABLE>
<CAPTION>

STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------------------------
                                                                           1999               1998            1999          1998
------------------------------------------------------------------------------------------------------------------------------------
                                                                               (in thousands)                (percent of total)
Long-Term Debt:
First mortgage bonds --

     Maturity                        Interest Rates
     ---------                       ---------------
     <S>                           <C>                                    <C>                <C>              <C>            <C>
     September 1, 1999               6.125%                               $        -         $  195,000
     March 1, 2000                   6.00%                                   100,000            100,000
     April 1, 2003                   6.625%                                  200,000            200,000
     August 1, 2003                  6.35%                                    75,000             75,000
     2005                            6.07%                                    10,000             10,000
     2008                            6.875%                                   50,000             50,000
     2023 through 2025               7.55% to 7.95%                           57,000            266,000
----------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                                   492,000            896,000
----------------------------------------------------------------------------------------------------------
Pollution control bonds -- (Note 9)
     Maturity                        Interest Rates
     --------                        --------------
     2000                            4.375%                                   50,000             50,000
     2005                            5.00%                                    57,000             57,000
     2011                            Variable (3.95% at 1/1/00)               10,450             10,450
     2018-2019                       6.00% to 6.35%                           13,100             63,100
     2020-2024                       5.75% to 6.25%                          192,270            377,270
     2022-2024                       Variable (3.70% to 5.05% at 1/1/00)     352,490            352,490
     2025                            6.00% to 6.10%                          145,115            145,115
     2025-2029                       Variable (3.70% to 5.05% at 1/1/00)     475,765            475,765
     2030-2034                       Variable (3.70% to 5.05% at 1/1/00)     140,000            140,000
     2034                            5.25% to 5.45%                          238,000                  -
----------------------------------------------------------------------------------------------------------
Total pollution control bonds                                              1,674,190           1,671,190
----------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
     Maturity                        Interest Rates
     --------                        --------------
     December 1, 2005                5.50%                                   150,000            150,000
     December 31, 2038               6.60%                                   200,000            200,000
     March 31, 2039                  6.625%                                  100,000                  -
     December 31, 2047               6.875%                                  145,000            145,000
----------------------------------------------------------------------------------------------------------
Total senior notes                                                           595,000            495,000
----------------------------------------------------------------------------------------------------------
Other long-term debt (Note 9)                                                 85,851             86,280
----------------------------------------------------------------------------------------------------------
Unamortized debt discount, net                                                (2,911)            (4,679)
----------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
     requirement -- $156,062,000)                                          2,844,130          3,143,791
Less amount due within one year (Note 9)                                     155,772            399,429
------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year                 $2,688,358         $2,744,362       36.2 %        38.0 %
------------------------------------------------------------------------------------------------------------------------------------


</TABLE>


                                                                  II-95


<PAGE>


<TABLE>
<CAPTION>

STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------------------
                                                                               1999                1998         1999         1998
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                (in thousands)                (percent of total)
Company Obligated Mandatorily
   Redeemable Preferred Securities (Note 9):
     <S>                                                                  <C>                   <C>            <C>           <C>
     $25 liquidation value -- 9.00%                                       $         -         $  100,000
     $25 liquidation value -- 7.75%                                           225,000            225,000
     $25 liquidation value -- 7.60%                                           175,000            175,000
     $25 liquidation value -- 7.75%                                           189,250            189,250
     $25 liquidation value -- 6.85%                                           200,000                  -
-----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59,104,000)                        789,250            689,250       10.6           9.5
-----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
     Authorized -- 55,000,000 shares
     Outstanding -- 149,520 shares at December 31, 1999
     Outstanding -- 511,834 shares at December 31, 1998
         $100 stated value --
            4.60% to 6.60%                                                     14,952             51,183
----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
     requirement -- $688,000)                                                  14,952             51,183
Less amount due within one year (Note 9)                                            -             35,656
-----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock excluding amount due within one year                14,952             15,527        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                                                             1,815,983          1,660,206
Premium on preferred stock                                                         40                158
Retained earnings (Note 9)                                                  1,777,937          1,779,558
-----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statement)              3,938,210          3,784,172       53.0          52.3
-----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                      $ 7,430,770        $ 7,233,311      100.0 %       100.0 %
-----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>



                                                                  II-96

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, 1997
Georgia Power Company 1999 Annual Report

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

                                                                                  Premium on
                                                        Common       Paid-In       Preferred       Retained
                                                         Stock       Capital         Stock         Earnings          Total
------------------------------------------------------------------------------------------------------------------------------
                                                                                (in thousands)

<S>                <C>                                <C>           <C>                 <C>       <C>              <C>
Balance at January 1, 1997                            $344,250      $2,134,886         $ 371      $1,674,774       $4,154,281
Net income after dividends on preferred stock                -               -             -         593,996          593,996
Capital distributions to parent company                      -        (205,000)            -               -         (205,000)
Capital contributions from parent company                    -              85             -               -               85
Cash dividends on common stock                               -               -             -        (520,000)        (520,000)
Preferred stock transactions, net                            -               -          (211)         (3,423)          (3,634)
------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997                           344,250       1,929,971           160       1,745,347        4,019,728
Net income after dividends on preferred stock                -               -             -         570,228          570,228
Capital distributions to parent company                      -        (270,000)            -               -         (270,000)
Capital contributions from parent company                    -             235             -               -              235
Cash dividends on common stock                               -               -             -        (536,600)        (536,600)
Preferred stock transactions, net                            -               -            (2)            583              581
------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                           344,250       1,660,206           158       1,779,558        3,784,172
Net income after dividends on preferred stock                -               -             -         541,383          541,383
Capital contributions from parent company                    -         155,777             -               -          155,777
Cash dividends on common stock                               -               -             -        (543,000)        (543,000)
Preferred stock transactions, net                            -               -          (118)             (4)            (122)
------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                          $344,250      $1,815,983         $  40      $1,777,937       $3,938,210
==============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-97

<PAGE>
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1999 Annual Report


1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five integrated Southeast utilities, Southern Company Services
(SCS), a system service company, Southern Communications Services (Southern
LINC), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating
Company (Southern Nuclear), Southern Company Energy Solutions, and other direct
and indirect subsidiaries. The integrated Southeast utilities (Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company) provide electric service in four
states. Contracts among the integrated Southeast utilities - related to jointly
owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC). SCS provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Company Energy Solutions develops new business opportunities related to
energy products and services. Southern Nuclear provides services to Southern
Company's nuclear power plants. Southern Energy acquires, develops, builds,
owns, and operates power production and delivery facilities and provides a broad
range of energy-related services to utilities and industrial companies in
selected countries around the world. Southern Energy's businesses include
independent power projects, integrated utilities, a distribution company, and
energy trading and marketing businesses outside the Southeastern United States.

    Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of this act. The Company is also
subject to regulation by the FERC and the Georgia Public Service Commission
(GPSC). The Company follows generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by the respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from
these estimates.

    Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.

Related-Party Transactions

The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $253 million, $251
million, and $218 million during 1999, 1998, and 1997, 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 $270 million, $269 million, and $220
million during 1999, 1998, and 1997, respectively.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues associated with
certain costs that are expected to be recovered from customers through the
ratemaking process. Regulatory liabilities represent probable future reductions
in revenues associated with amounts that are expected to be credited to
customers through the ratemaking process. Pursuant to the terms of the GPSC's
1998 rate order, the Company recorded $85 million in 1999 of additional
amortization of premium on reacquired debt. See Note 3 under "Retail Rate
Orders" for additional information. Regulatory assets and (liabilities)
reflected in the Company's Balance Sheets at December 31 relate to the
following:

                                      II-98

<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report



                                              1999       1998
                                        -----------------------
                                               (in millions)
Deferred income taxes                        $ 591      $ 604
Deferred income tax credits                   (267)      (284)
Premium on reacquired debt                      99        174
Corporate building lease                        54         53
Vacation pay                                    47         44
Postretirement benefits                         33         36
Department of Energy assessments                24         26
Deferred nuclear outage costs                   26         24
Other, net                                       3         12
---------------------------------------------------------------
Total                                        $ 610      $ 689
===============================================================

    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 accrues revenues for service rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as the fuel is used. The Company's
electric rates include provisions to adjust billings for fluctuations in fuel
costs, the energy component of purchased power costs, and certain other costs.
Revenues are adjusted for differences between recoverable fuel costs and amounts
actually recovered in current rates.

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

    Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $74
million in 1999, $74 million in 1998, and $76 million in 1997. The Company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent fuel in January 1998 as required by the contracts, and the Company is
pursuing legal remedies against the government for breach of contract.
Sufficient storage capacity currently is available to permit operation into 2003
at Plant Hatch and into 2017 at Plant Vogtle. Plant Vogtle's spent fuel storage
capacity includes the installation in 1998 of additional rack capacity.
Activities for adding dry cask storage capacity and potentially additional spent
fuel pool rack capacity at Plant Hatch during 2000 are in progress. In addition,
through Southern Nuclear, Georgia Power is a member of Private Fuel Storage,
LLC, a joint utility effort to develop a private spent fuel storage facility for
temporary storage of spent nuclear fuel. This facility is planned to begin
operation as early as the year 2003.

    Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is to be funded in
part by a special assessment on utilities with nuclear plants. This fund will be
used by the DOE for the decontamination and decommissioning of its nuclear fuel
enrichment facilities. The assessment will be paid over a 15-year period, which
began in 1993. 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,
1999, to be approximately $21.4 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 1999, 3.2 percent in 1998, and 3.1 percent in 1997. In addition,
the Company recorded accelerated depreciation of electric plant of $314 million
in 1998 and $159 million in 1997.  The Company did not record any accelerated
depreciation in 1999. These charges are recorded in the accumulated provision
for depreciation. See Note 3 under "Retail Rate Orders" for additional
information. 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 costs of decommissioning nuclear facilities
and removal of other facilities.

                                       II-99

<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


    Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial nuclear power reactors to establish a plan for providing,
with reasonable assurance, funds for decommissioning. The Company has
established external trust funds to comply with the NRC's regulations. Amounts
previously recorded in internal reserves are being transferred into the external
trust funds over a set period of time as ordered by the GPSC. Earnings on the
trust funds are considered in determining decommissioning expense. The NRC's
minimum external funding requirements are based on a generic estimate of the
cost to decommission the radioactive portions of a nuclear unit based on the
size and type of reactor. The Company has filed plans with the NRC to ensure
that -- over time -- the deposits and earnings of the external trust funds will
provide the minimum funding amounts prescribed by the NRC.

        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 3.6 percent for
the Company's ownership interests are as follows:

                                          Plant        Plant
                                          Hatch       Vogtle
                                         ----------------------
Site study basis (year)                    1997         1997

Decommissioning periods:
   Beginning year                          2014         2027
   Completion year                         2027         2038
---------------------------------------------------------------
                                              (in millions)
Site study costs:
   Radiated structures                     $372         $317
   Non-radiated structures                   33           44
---------------------------------------------------------------
Total                                      $405         $361
===============================================================
                                              (in millions)
Ultimate costs:
   Radiated structures                     $722       $  922
   Non-radiated structures                   65          129
-------------------------------------------------------------
Total                                      $787       $1,051
=============================================================

    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, changes in the assumptions used in
making 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 1999 and fund
balance as of December 31, 1999 were:

                                              Plant      Plant
                                              Hatch     Vogtle
---------------------------------------------------------------
                                               (in millions)
  Amount expensed in 1999                    $ 17      $  9
===============================================================
                                               (in millions)

  Accumulated provisions:
   External trust funds, at fair value       $222      $149
   Internal reserves                           22        12
---------------------------------------------------------------
  Total                                      $244      $161
===============================================================

    Effective January 1, 1999, the GPSC increased the annual provision for
decommissioning expenses to $26 million from $20 million in 1998 and 1997. This
amount is based on the NRC generic estimate to decommission the radioactive
portion of the facilities as of 1997 of $526 million and $438 million for plants
Hatch and Vogtle, respectively. The ultimate costs associated with the 1997 NRC
minimum funding requirements are $1.1 billion and $1.3 billion for plants Hatch
and Vogtle, respectively. Significant assumptions include an estimated inflation
rate of 3.6 percent and an estimated trust earnings rate of 6.5 percent. The
Company expects the GPSC to periodically review and adjust, if necessary, the
amounts collected in rates for the anticipated cost of decommissioning.

Income Taxes

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

                                       II-100


<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report

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. For the years 1999, 1998 and 1997, the average AFUDC rates
were 5.61 percent, 6.71 percent and 7.60 percent, respectively. AFUDC, net of
taxes, as a percentage of net income after dividends on preferred stock, was
less than 2.0 percent for 1999, 1998, and 1997.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost, less regulatory
disallowances and impairments. Original cost includes: materials; labor;
payroll-related costs such as taxes, pensions, and other benefits; and the cost
of funds used during construction. The cost of maintenance, repairs, and
replacement of minor items of property is charged to maintenance expense. The
cost of replacements of property (exclusive of minor items of property) is
capitalized.

Cash and Cash Equivalents

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

Financial Instruments

The Company'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, 1999                   $2,758      $2,604
  At December 31, 1998                    3,058       3,105
Preferred securities:
  At December 31, 1999                      789         680
  At December 31, 1998                      689         716
--------------------------------------------------------------

    The fair values for securities were based on either closing market prices or
closing prices of comparable instruments.

Materials and Supplies

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

2.  RETIREMENT BENEFITS

The Company has defined benefit, trusteed pension plans that cover substantially
all employees. The Company provides certain medical care and life insurance
benefits for retired employees. Substantially all these employees may become
eligible for such benefits when they retire. The Company funds postretirement
trusts to the extent required by the GPSC and FERC. The measurement date for
plan assets and obligations is September 30 of each year.

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

                                               1999       1998
-----------------------------------------------------------------
Discount                                       7.50%      6.75%
Annual salary increase                         5.00       4.25
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
                                     ---------------------------
                                           1999          1998
----------------------------------------------------------------
                                           (in millions)
Balance at beginning of year             $1,217        $1,119
Service cost                                 33            30
Interest cost                                80            82
Benefits paid                               (57)          (55)
Actuarial (gain) loss and
    employee transfers                      (68)           41
----------------------------------------------------------------
Balance at end of year                   $1,205        $1,217
================================================================


                                     II-101

<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report

                                              Plan Assets
                                     ---------------------------
                                           1999          1998
----------------------------------------------------------------
                                           (in millions)
Balance at beginning of year             $1,859        $1,931
Actual return on plan assets                313            11
Benefits paid                               (57)          (55)
Employee transfers                           (8)          (28)
----------------------------------------------------------------
Balance at end of year                   $2,107        $1,859
================================================================

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

                                              1999       1998
---------------------------------------------------------------
                                              (in millions)
Funded status                               $  902     $  642
Unrecognized transition obligation             (30)       (35)
Unrecognized prior service cost                 41         45
Unrecognized net actuarial gain               (767)      (548)
---------------------------------------------------------------
Prepaid asset recognized in the
      Balance Sheets                        $  146     $  104
===============================================================

    Components of the plans' net periodic cost were as follows:

                                         1999    1998     1997
---------------------------------------------------------------
                                            (in millions)
Service cost                            $  33   $  30    $  30
Interest cost                              80      82       82
Expected return on plan assets           (137)   (127)    (121)
Recognized net actuarial gain             (17)    (20)     (18)
Net amortization                           (1)     (1)      (1)
---------------------------------------------------------------
Net pension income                      $ (42)  $ (36)   $ (28)
===============================================================

Postretirement Benefits

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

                                              Accumulated
                                         Benefit Obligations
                                     ---------------------------
                                          1999          1998
----------------------------------------------------------------
                                           (in millions)
Balance at beginning of year              $464          $435
Service cost                                 8             7
Interest cost                               30            32
Benefits paid                              (19)          (16)
Actuarial loss and employee
    transfers                              (45)            6

----------------------------------------------------------------
Balance at end of year                    $438          $464
=================================================================

                                            Plan Assets
                                     ---------------------------
                                          1999          1998
----------------------------------------------------------------
                                           (in millions)
Balance at beginning of year              $150          $122
Actual return on plan assets                11             4
Employer contributions                      35            40
Benefits paid                              (19)          (16)
----------------------------------------------------------------
Balance at end of year                    $177          $150
================================================================

    The accrued postretirement costs recognized in the Balance Sheets were
as follows:
                                              1999      1998
---------------------------------------------------------------
                                              (in millions)
Funded status                                $(261)     $(314)
Unrecognized transition obligation             122        131
Unrecognized net actuarial loss                 10         57
Fourth quarter contributions                    14         19
---------------------------------------------------------------
Accrued liability recognized in the
      Balance Sheets                         $(115)    $(107)
===============================================================

    Components of the plans' net periodic cost were as follows:

                                         1999    1998     1997
---------------------------------------------------------------
                                            (in millions)
Service cost                             $  8     $ 7      $ 7
Interest cost                              30      32       32
Expected return on plan assets            (10)     (9)      (7)
Recognized net actuarial loss               1       1        1
Net amortization                            9       9        9
---------------------------------------------------------------
Net postretirement cost                  $ 38     $40      $42
===============================================================

      An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1999 as follows:

                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
                                           (in millions)
Benefit obligation                      $ 36         $ (30)
Service and interest costs                 3            (3)
===============================================================

                                       II-102

<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


3. CONTINGENCIES & REGULATORY MATTERS


Retail Rate Orders

On December 18, 1998, the GPSC approved a new three-year rate order for the
Company. Under terms of the order, earnings will continue to be evaluated
against a retail return on common equity range of 10 percent to 12.5 percent.
Retail rates were decreased by $262 million on an annual basis effective January
1, 1999, and by an additional $24 million effective January 1, 2000. The order
further provides for $85 million in each year, plus up to $50 million of any
earnings above the 12.5 percent return during the second and third years, to be
applied to accelerated amortization or depreciation of assets. Two-thirds of any
additional earnings above the 12.5 percent return will be applied to rate
reductions, with the remaining one-third retained by the Company. Pursuant to
the order, in 1999 the Company recorded $85 million in accelerated amortization
of premium on reacquired debt. The Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent retail return on
common equity. Refunds will be made to customers in 2000. This refund is
presented in the financial statements under other current liabilities on the
Balance Sheet. The Company will not file for a general base rate increase unless
its projected retail return on common equity falls below 10 percent, and is
required to file a general rate case on July 1, 2001, in response to which the
GPSC would be expected to determine whether the rate order should be continued,
modified, or discontinued.

    Under a previous three-year accounting order ending December 1998, the
Company's earnings were evaluated against a retail return on common equity range
of 10 percent to 12.5 percent. Earnings above 12.5 percent were used to
accelerate the amortization of regulatory assets or depreciation of electric
plant. Additionally, the Company was required to record $14 million annually of
accelerated depreciation of electric plant. During 1998 and 1997, for earnings
above the 12.5 percent retail return, the Company recorded charges of $292
million and $135 million, respectively. These charges are presented in the
financial statements as depreciation expense of electric plant and as an
addition to the accumulated provision for depreciation.

Environmental Protection Agency (EPA) Litigation

On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. The civil action requests penalties and injunctive
relief, including an order requiring the installation of the best available
control technology at the affected units beginning at the point of the alleged
violations. The Clean Air Act authorizes civil penalties of up to $27,500 per
day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.

    The EPA concurrently issued a notice of violation to the Company relating to
these two plants. In early 2000, the EPA filed a motion to amend its complaint
to add the violations alleged in its notice of violation. The complaint and the
notice of violation are similar to those brought against and issued to several
other electric utilities. The complaint and the notice of violation allege that
the Company failed to secure necessary permits or install additional pollution
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. The Company believes that it
complied with applicable laws and the EPA's regulations and interpretations in
effect at the time the work in question took place

    An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates.

Other Environmental Contingencies

The State of Georgia submitted a plan for nitrogen oxide emission reductions in
Atlanta's ozone non-attainment area on October 29, 1999. The EPA found this plan
to be deficient and required the State to address the shortfalls of the plan.
Based on the revised plan approved by the Georgia Department of Natural
Resources on January 26, 2000, the Company estimates its capital costs to comply
with the plan to be approximately $713 million through 2003, of which $705
million remains to be spent. It is still uncertain at this time what additional
controls may be required at the Company's plants beyond the recently submitted
plan.

    In January 1995, the Company and four other unrelated entities were notified
by the EPA that they have been designated as potentially responsible parties
under the Comprehensive Environmental Response, Compensation and Liability Act

                                       II-103

<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


with respect to a site in Brunswick, Georgia. As of December 31, 1999, the
Company has recognized approximately $5 million in cumulative expenses
associated with this site. This represents the Company's agreed upon share of
removal and remedial investigation and feasibility study costs. The final
outcome of this matter cannot now be determined. However, based on the nature
and extent of the Company's activities relating to the site, management believes
that the Company's portion of any remaining remediation costs should not be
material.

    In compliance with the Georgia Hazardous Site Response Act of 1993, the
State of Georgia was required to compile an inventory of all known or suspected
sites where hazardous wastes, constituents or substances have been disposed of
or released in quantities deemed reportable by the State. In developing this
list, the State identified several hundred properties throughout the State,
including 31 sites which may require environmental remediation that were either
previously or are currently owned by the Company. The majority of these sites
are electrical power substations and power generation facilities. The Company
has remediated ten electrical substations on the list at a cumulative cost of
approximately $3 million through December 31, 1999. The State has removed from
the list two power generation facilities following the assessment which
indicated no remediation was necessary. In addition, the Company has recognized
approximately $26 million in cumulative expenses through December 31, 1999 for
the assessment of the remaining sites on the list and the anticipated clean-up
cost for 12 sites that the Company plans to remediate. Any cost of remediating
the remaining sites cannot presently be determined until such studies are
completed for each site and the State determines whether remediation is
required. If all listed sites were required to be remediated, the Company could
incur expenses of up to approximately $6 million in additional clean-up costs
and construction expenditures of up to approximately $37 million to develop new
waste management facilities or install additional pollution control devices.

    The accrued costs for environmental remediation obligations are not
discounted to their present value.

Rocky Mountain Status

In June 1996, the GPSC initiated a review of the Rocky Mountain plant. On
January 14, 1998, the GPSC ordered that the Company be allowed approximately
$108 million of its $142 million investment in the plant in rate base as of
December 31, 1998. Under the rate order approved by the GPSC on December 18,
1998, the Company accepted the rate base allowance and, in December 1998,
recorded a charge to earnings of $21 million, after taxes, associated with the
write-down of the plant.

Tax Litigation

In August 1997, Southern Company and the Internal Revenue Service (IRS) entered
into a settlement agreement related to tax issues for the years 1984 through
1987. The agreement received final approval by the Joint Congressional Committee
on Taxation in June 1998 and as a result, the Company recognized interest income
in 1998 of $69 million. The refund by the IRS has been made and this matter is
now concluded.

    Additionally, the Company received a refund from the State of Georgia
pertaining to the same issues and recognized an additional $4 million in
interest income in 1998.

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.

    In January 1997, the GPSC approved a performance award of approximately
$11.7 million for performance during the 1993-1995 period. This award was
collected through the retail fuel cost recovery provision and recognized in
income over the 36-month period ending in December 1999. In February 2000, the
GPSC approved a performance award of approximately $7.8 million for performance
during the 1996-1998 period. This award is being collected through the retail
fuel cost recovery provision and recognized in income over a 36-month period
that began in January 2000.

                                       II-104


<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


4.  COMMITMENTS

Construction Program

The Company is constructing a ten unit, 800 megawatt combustion turbine peaking
power plant. Units one through eight will begin operation in 2000; units nine
and ten will begin operation in 2001. The Company also plans to construct a 570
megawatt combined cycle unit that will begin operation in 2002, and an addition
of two 568 megawatt combined cycle units at Plant Wansley, to begin operation in
2002. In addition, significant construction of transmission and distribution
facilities, and projects to upgrade and extend the useful life of generating
plants and to remain in compliance with environmental requirements will
continue. The Company currently estimates property additions to be approximately
$1.2 billion in 2000, $1.5 billion in 2001, and $1.5 billion in 2002.

    The construction program is subject to periodic review and revision, and
actual construction costs may vary from estimates because of numerous factors,
including, but not limited to, changes in business conditions, load growth
estimates, environmental regulations, and regulatory requirements.

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term fossil and nuclear fuel commitments at December 31,
1999 were as follows:

                                                Minimum
Year                                           Obligations
----                                          ------------
                                             (in millions)
2000                                              $  659
2001                                                 475
2002                                                 381
2003                                                 328
2004                                                 300
2005 and beyond                                      787
----------------------------------------------------------------
Total minimum obligations                         $2,930
================================================================

   Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.

Purchased Power Commitments

The Company and an affiliate, Alabama Power Company, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
owns electric generating units with a total rated capacity of 1,020 megawatts,
as well as associated transmission facilities. The capacity of the units has
been sold equally to the Company and Alabama Power Company under a contract
which, in substance, requires payments sufficient to provide for the operating
expenses, taxes, debt service and return on investment, whether or not SEGCO has
any capacity and energy available. The term of the contract extends
automatically for two-year periods, subject to either party's right to cancel
upon two year's notice. The Company's share of expenses included in purchased
power from affiliates in the Statements of Income, is as follows:

                                1999        1998       1997
                             ---------------------------------
                                     (in millions)
Energy                           $51         $45        $45
Capacity                          29          30         30
--------------------------------------------------------------
Total                            $80         $75        $75
==============================================================
Kilowatt-hours                 3,338       3,146      3,038
--------------------------------------------------------------

    The Company has commitments regarding a portion of a 5 percent interest in
Plant Vogtle owned by 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 $57 million, $56 million, and
$54 million in 1999, 1998, and 1997, respectively. The current projected Plant
Vogtle capacity payments are:


Year                                         Capacity Payments
----                                      ----------------------
                                              (in millions)
2000                                              $   60
2001                                                  59
2002                                                  58
2003                                                  58
2004                                                  55
2005 and beyond                                      594
----------------------------------------------------------------
Total capacity payments                           $  884
================================================================


                                     II-105


<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


    Portions of the payments noted above relate to costs in excess of Plant
Vogtle's allowed investment for ratemaking purposes. The present value of these
portions was written off in 1987 and 1990.

    The Company has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
1999 were as follows:

Year                                        Other Obligations
---                                       ----------------------
                                              (in millions)
2000                                              $  21
2001                                                 22
2002                                                 39
2003                                                 41
2004                                                 40
2005 and beyond                                     412
----------------------------------------------------------------
Total other obligations                           $ 575
================================================================

Operating Leases

The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $11 million for 1999, $13 million
for 1998, and $11 million for 1997. At December 31, 1999, estimated minimum
rental commitments for these noncancelable operating leases were as follows:

Year                                      Minimum Obligations
----                                   --------------------------
                                             (in millions)
2000                                            $  12
2001                                               13
2002                                               13
2003                                               13
2004                                               13
2005 and beyond                                   115
-----------------------------------------------------------------
Total minimum obligations                       $ 179
=================================================================

5.  NUCLEAR INSURANCE

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

    The Company is a member of Nuclear Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.

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

    NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can be insured against increased costs of replacement power in an
amount up to $3.5 million per week -- starting 12 weeks after the outage -- for
one year and up to $2.8 million per week for the second and third years.

    Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $21 million.

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

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

                                       II-106


<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


6.  JOINT OWNERSHIP AGREEMENTS

Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned generating facilities. The Company includes its proportionate
share of plant operating expenses in the corresponding operating expenses in the
Statements of Income.

    The Company jointly owns the Rocky Mountain pumped storage hydroelectric
plant with OPC 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 operated by FPC.

    At December 31, 1999, 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%      $3,297*        $1,630
Plant Hatch (nuclear)            50.1          857            604
Plant Wansley (coal)             53.5          299            145
Plant Scherer (coal)
   Units 1 and 2                  8.4          112             51
   Unit 3                        75.0          544            193
Plant McIntosh
 Common Facilities               75.0           19              1
   (combustion-turbine)
Rocky Mountain                   25.4          169*            66
  (pumped storage)
Intercession City                33.3           11             **
  (combustion-turbine)
--------------------------------------------------------------------
     * Investment net of write-offs.
    ** Less than $1 million.

7.  LONG-TERM POWER SALES AGREEMENTS

The Company and the other integrated Southeast utilities of Southern Company
have long-term contractual agreements for the sale of capacity and energy to
non-affiliated utilities located outside the system's service area. These
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)
               1999        $  32           162
               1998           32           162
               1997           42           159
               -------------------------------------

    Unit power from specific generating plants is being sold to Florida Power &
Light Company (FP&L), FPC, Jacksonville Electric Authority (JEA), and the City
of Tallahassee, Florida. Under these agreements, the Company sold approximately
162 megawatts of capacity in 1999 and is scheduled to sell approximately 124
megawatts of capacity in 2000. After 2000, capacity sales will decline to
approximately 101 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the
expiration of the contracts in 2010.

8.  INCOME TAXES

At December 31, 1999, tax-related regulatory assets were $591 million and
tax-related regulatory liabilities were $267 million. The assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized AFUDC. 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:

                                     1999       1998       1997
                                  -------------------------------
Total provision for income taxes:          (in millions)
Federal:
   Currently payable                $ 333       $415      $352
   Deferred -
     Current year                     114        131        49
     Reversal of prior years         (148)      (218)      (68)
   Deferred investment tax
     credits                            -          7         -
-----------------------------------------------------------------
                                      299        335       333
-----------------------------------------------------------------
State:
   Currently payable                   54         77        65
   Deferred -
     Current year                       5         18         8
     Reversal of prior years          (11)       (31)      (11)
   Deferred investment tax
     credits                            5          -         -
-----------------------------------------------------------------
                                       53         64        62
-----------------------------------------------------------------
Total                                 352        399       395
=================================================================



                                       II-107
<PAGE>
NOTES (continued)
Georgia Power Company 1999 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:

                                                1999      1998
                                              -------------------
                                                (in millions)
Deferred tax liabilities:
   Accelerated depreciation                     $1,766    $1,670
   Property basis differences                      729       854
   Other                                           155       158
-----------------------------------------------------------------
Total                                            2,650     2,682
-----------------------------------------------------------------
Deferred tax assets:
   Other property basis differences                200       211
   Federal effect of state deferred taxes           93        95
   Other deferred costs                            109        96
   Disallowed Plant Vogtle buybacks                 22        23
   Other                                            26        21
-----------------------------------------------------------------
Total                                              450       446
-----------------------------------------------------------------
Net deferred tax liabilities                     2,200     2,236
Portion included in current assets                   3        13
-----------------------------------------------------------------
Accumulated deferred income taxes
   in the Balance Sheets                        $2,203    $2,249
=================================================================

    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 $20 million in 1999, $22 million in 1998, and $15 million in 1997.
At December 31, 1999, all investment tax credits available to reduce federal
income taxes payable had been utilized.

    A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:

                                      1999     1998     1997
                                     --------------------------
Federal statutory rate                  35%      35%      35%
State income tax, net of
   federal deduction                     4        4        4
Non-deductible book
   depreciation                          2        6        4
Other                                   (2)      (4)      (4)
---------------------------------------------------------------
Effective income tax rate               39%      41%      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.

9.  CAPITALIZATION

First Mortgage Bond Indenture & Charter Restrictions

The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.

    The Company's first mortgage bond indenture contains various restrictions
that remain in effect as long as the bonds are outstanding. At December 31,
1999, $881 million of retained earnings and paid-in capital was unrestricted for
the payment of cash dividends or any other distributions under terms of the
mortgage indenture. If additional first mortgage bonds are issued, supplemental
indentures in connection with those issues may contain more stringent
restrictions than those currently in effect.

Preferred Securities

Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:

              Date of                                   Maturity
               Issue      Amount     Rate    Notes        Date
            ---------------------------------------------------
                        (millions)          (millions)
Trust I       8/1996     $225.00     7.75%    $232       6/2036
Trust II      1/1997      175.00     7.60      180      12/2036
Trust III     6/1997      189.25     7.75      195       3/2037
Trust IV      2/1999      200.00     6.85      206       3/2029

    Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above.

    The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.

    The Trusts are subsidiaries of the Company, and accordingly are consolidated
in the Company's financial statements.



                                       II-108

<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


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 $457.5 million of its
first mortgage bonds outstanding at December 31, 1999, which are pledged as
security for its obligations under pollution control revenue contracts. No
interest on these first mortgage bonds is payable unless and until a default
occurs on the installment purchase or loan agreements.

Senior Notes

The Company incurred debt in connection with the issuance of unsecured senior
notes. The senior notes are, in effect, subordinated to all secured debt of the
Company, including its first mortgage bonds.

Bank Credit Arrangements

At the beginning of 2000, the Company had unused credit arrangements with banks
totaling $1.3 billion, of which $752 million expires at various times during
2000, and $500 million expires at April 24, 2003.

    Of the total $1.3 billion in unused credit, $1 billion is a syndicated
credit arrangement with $500 million expiring April 20, 2000, and $500 million
expiring April 24, 2003. Both agreements provide the option of converting
borrowings into two-year term loans upon expiration date. The 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 $162 million of the $752 million arrangements expiring during
2000 allow for two-year term loans executable upon expiration date of the
facilities. The $30 million credit arrangement expiring at May 1, 2000, allows
for term loans of up to three years. 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.

    These unused credit arrangements provide 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,
1999, was $250 million.

    In addition, the Company borrows under uncommitted lines of credit with
banks and through a $500 million commercial paper program that has the liquidity
support of committed bank credit arrangements. Average compensating balances
held under these committed facilities were not material in 1999.

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, 1999 and 1998, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million with an
interest rate of 8.1 percent. The lease agreement provides for payments that are
minimal in early years and escalate through the first 21 years of the lease. For
ratemaking purposes, the GPSC has treated the lease as an operating lease and
has allowed only the lease payments in cost of service. The difference between
the accrued expense and the lease payments allowed for ratemaking purposes is
being deferred as a cost to be recovered in the future as ordered by the GPSC.
At December 31, 1999 and 1998, the interest and lease amortization deferred on
the Balance Sheets are $54 million and $53 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-109


<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report


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:

                                                1999      1998
                                             ------------------
                                               (in millions)

Bond improvement fund requirements              $  5      $  9
Capital lease - current portion                    1         -
First mortgage bond maturities
   and redemptions                               100       390
Pollution control bond maturities
     and redemptions                              50         -
---------------------------------------------------------------

Total long-term debt                             156       399
Preferred stock                                    -        36
---------------------------------------------------------------

Total                                           $156      $435
===============================================================

    The Company's first mortgage bond indenture includes an improvement fund
requirement that amounts to 1 percent of each outstanding series of bonds
authenticated under the indenture prior to January 1 of each year, other than
those issued to collateralize pollution control obligations. The requirement may
be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement.

Redemption of Securities

The Company plans to continue, to the extent possible, a program of redeeming or
replacing debt and preferred stock in cases where opportunities exist to reduce
financing costs. Issues may be repurchased in the open market or called at
premiums as specified under terms of the issue. They may also be redeemed at
face value to meet improvement fund requirements, to meet replacement provisions
of the mortgage, or through use of proceeds from the sale of property pledged
under the mortgage. In general, for the first five years a series of first
mortgage bonds is outstanding, the Company is prohibited from redeeming for
improvement fund purposes more than 1 percent annually of the original issue
amount.

10. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial information for 1999 and 1998 is as follows:

                                                       Net Income
                                                          After
                                                       Dividends on
                          Operating     Operating        Preferred
     Quarter Ended        Revenues       Income            Stock
---------------------------------------------------------------------
                                        (in millions)
                         --------------------------------------------
March 1999                 $   931         $224          $  92
June 1999                    1,092          299            138
September 1999               1,466          557            296
December 1999                  968          200             15


March 1998                 $   984         $257          $ 106
June 1998                    1,226          286            137
September 1998               1,530          514            255
December 1998                  998          143             72
---------------------------------------------------------------------

    Under the 1998 rate order, the Company recorded $85 million of accelerated
amortization which was recorded monthly throughout 1999 as an operating expense.
See Note 3 to the financial statements under "Retail Rate Orders" for additional
information. In December 1999, in accordance with the order, the Company
reclassified this $85 million to amortization of premium on reacquired debt. The
1999 fourth quarter operating income reflects this reclassification.

    The quarterly operating income data above has been reclassified to reflect
the Company's current presentation of income tax expense.

    The Company's business is influenced by seasonal weather conditions.



                                       II-110



<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Georgia Power Company 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------------------
                                                           1999            1998            1997            1996            1995
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>             <C>             <C>             <C>             <C>
Operating Revenues (in thousands)                    $4,456,675      $4,738,253      $4,385,717      $4,416,779      $4,405,338
Net Income after Dividends
  on Preferred Stock (in thousands)                    $541,383        $570,228        $593,996        $580,327        $608,862
Cash Dividends
  on Common Stock (in thousands)                       $543,000        $536,600        $520,000        $475,500        $451,500
Return on Average Common Equity (percent)                 14.02           14.61           14.53           13.73           14.43
Total Assets (in thousands)                         $12,276,860     $12,033,618     $12,573,728     $13,006,635     $13,470,275
Gross Property Additions (in thousands)                $790,464        $499,053        $475,921        $428,220        $480,449
--------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                  $3,938,210      $3,784,172      $4,019,728      $4,154,281      $4,299,012
Preferred stock                                          14,952          15,527         157,247         464,611         692,787
Company obligated mandatorily
  redeemable preferred securities                       789,250         689,250         689,250         325,000         100,000
Long-term debt                                        2,688,358       2,744,362       2,982,835       3,200,419       3,315,460
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)        $7,430,770      $7,233,311      $7,849,060      $8,144,311      $8,407,259
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                        53.0            52.3            51.2            51.0            51.1
Preferred stock                                             0.2             0.2             2.0             5.7             8.2
Company obligated mandatorily
  redeemable preferred securities                          10.6             9.5             8.8             4.0             1.2
Long-term debt                                             36.2            38.0            38.0            39.3            39.5
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)             100.0           100.0           100.0           100.0           100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
    Moody's                                                  A1              A1              A1              A1              A1
    Standard and Poor's                                      A+              A+              A+              A+              A+
    Duff & Phelps                                           AA-             AA-             AA-             AA-             AA-
Preferred Stock -
    Moody's                                                  a2              a2              a2              a2              a2
    Standard and Poor's                                      A-               A               A               A               A
    Duff & Phelps                                            A+              A+              A+              A+               A
Unsecured Long-Term Debt -
    Moody's                                                  A2              A2              A2              A2              A2
    Standard and Poor's                                       A               A               A               A               A
    Duff & Phelps                                            A+              A+              A+              A+              A+
================================================================================================================================
Customers (year-end):
Residential                                           1,632,450       1,596,488       1,561,675       1,531,453       1,500,024
Commercial                                              229,524         221,180         211,672         205,087         198,624
Industrial                                                8,958           9,485           9,988          10,424          10,796
Other                                                     3,060           3,034           2,748           2,645           2,568
--------------------------------------------------------------------------------------------------------------------------------
Total                                                 1,873,992       1,830,187       1,786,083       1,749,609       1,712,012
================================================================================================================================
Employees (year-end):                                     8,961           8,371           8,354          10,346          11,061
--------------------------------------------------------------------------------------------------------------------------------

</TABLE>



                                                                  II-111
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Georgia Power Company 1999 Annual Report

-------------------------------------------------------------------------------------------------------------------------------
                                                           1999            1998            1997            1996            1995
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>              <C>            <C>             <C>             <C>
Operating Revenues (in thousands):
Residential                                         $ 1,410,099      $1,486,699     $ 1,326,787     $ 1,371,033     $ 1,337,060
Commercial                                            1,527,880       1,591,363       1,493,353       1,486,586       1,449,108
Industrial                                            1,143,001       1,170,881       1,110,311       1,118,633       1,141,766
Other                                                   (30,892)         49,274          47,848          47,060          44,255
-------------------------------------------------------------------------------------------------------------------------------
Total retail                                          4,050,088       4,298,217       3,978,299       4,023,312       3,972,189
Sales for resale  - non-affiliates                      210,104         259,234         282,365         281,580         290,302
Sales for resale  - affiliates                           76,426          81,606          38,708          35,886          76,906
-------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity              4,336,618       4,639,057       4,299,372       4,340,778       4,339,397
Other revenues                                          120,057          99,196          86,345          76,001          65,941
-------------------------------------------------------------------------------------------------------------------------------
Total                                                $4,456,675      $4,738,253      $4,385,717      $4,416,779      $4,405,338
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential                                          19,404,709      19,481,486      17,295,022      17,826,451      17,307,399
Commercial                                           23,715,485      22,861,391      21,134,346      20,823,073      19,844,999
Industrial                                           27,300,355      27,283,147      26,701,685      26,191,831      25,286,340
Other                                                   551,451         543,462         538,163         536,057         493,720
-------------------------------------------------------------------------------------------------------------------------------
Total retail                                         70,972,000      70,169,486      65,669,216      65,377,412      62,932,458
Sales for resale  - non-affiliates                    5,060,931       6,438,891       6,795,300       7,868,342       6,591,841
Sales for resale  - affiliates                        1,795,243       2,038,400       1,706,699       1,180,207       2,738,947
-------------------------------------------------------------------------------------------------------------------------------
Total                                                77,828,174      78,646,777      74,171,215      74,425,961      72,263,246
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                                7.27            7.63            7.67            7.69            7.73
Commercial                                                 6.44            6.96            7.07            7.14            7.30
Industrial                                                 4.19            4.29            4.16            4.27            4.52
Total retail                                               5.71            6.13            6.06            6.15            6.31
Sales for resale                                           4.18            4.02            3.78            3.51            3.94
Total sales                                                5.57            5.90            5.80            5.83            6.00
Residential Average Annual
  Kilowatt-Hour Use Per Customer                         12,006          12,314          11,171          11,763          11,654
Residential Average Annual
  Revenue Per Customer                                  $872.47         $939.73         $857.01         $904.70         $900.28
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                         14,474          14,437          14,437          14,367          14,344
Maximum Peak-Hour Demand (megawatts):
Winter                                                   11,568          11,959          10,407          10,410           9,819
Summer                                                   14,575          13,923          13,153          12,914          12,828
Annual Load Factor (percent)                               58.9            58.7            57.4            62.2            59.6
Plant Availability (percent):

Fossil-steam                                               84.3            86.0            85.8            85.2            85.8
Nuclear                                                    89.3            91.6            88.8            89.3            91.8
-------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                       63.0            62.3            64.3            60.4            63.0
Nuclear                                                    18.0            18.3            18.8            18.2            19.3
Hydro                                                       0.9             2.2             2.2             2.2             2.5
Oil and gas                                                 1.6             2.2             0.6             0.5             0.6
Purchased power -
  From non-affiliates                                       6.6             6.5             2.7             5.6             7.7
  From affiliates                                           9.9             8.5            11.4            13.1             6.9
-------------------------------------------------------------------------------------------------------------------------------
Total                                                     100.0           100.0           100.0           100.0           100.0
===============================================================================================================================
</TABLE>


                                                                  II-112


<PAGE>


                               GULF POWER COMPANY

                               FIANANCIAL SECTION






                                     II-113



<PAGE>
MANAGEMENT'S REPORT
Gulf Power Company 1999 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 generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.

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

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

   The audit committee of the board of directors, composed of directors who are
not employees, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.

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

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




/s/Travis J. Bowden
Travis J. Bowden
President
and Chief Executive Officer


/s/Arlan E. Scarbrough
Arlan E. Scarbrough
Chief Financial Officer


February 16, 2000




                                       II-114


<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, 1999 and 1998, and the related statements
of income, common stockholder's equity, and cash flows for each of the three
years in the period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

   In our opinion, the financial statements (pages 11-124 through II-139)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 1999 and 1998, and the results
of its operations and its cash flows for each of the three years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.


/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000






                                       II-115


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1999 Annual Report


RESULTS OF OPERATIONS

Earnings

Gulf Power Company's 1999 net income after dividends on preferred stock was
$53.7 million, a decrease of $2.8 million from the previous year. In 1998,
earnings were $56.5 million, down $1.1 million when compared to 1997. The
decrease in earnings in 1999, as well as 1998, was primarily a result of higher
expenses than in the prior year.

Revenues

Operating revenues increased in 1999 and 1998 when compared to 1998 and 1997,
respectively. The following table summarizes the factors impacting operating
revenues for the past three years:

                                      Increase (Decrease)
                                        From Prior Year
                             ---------------------------------------
                                  1999        1998         1997
                             ---------------------------------------
                                         (in thousands)
Retail --
   Growth and
     price change              $10,348     $15,021      $ 4,005
   Weather                      (7,879)      6,656       (5,277)
   Regulatory cost
     recovery and other          1,173     (34,179)      (7,837)
--------------------------------------------------------------------
Total retail                     3,642     (12,502)      (9,109)
--------------------------------------------------------------------
Sales for resale--
   Non-affiliates                  461      (1,804)         496
   Affiliates                   23,468      25,882       (1,002)
--------------------------------------------------------------------
Total sales for resale          23,929      24,078         (506)
Other operating
   revenues                     (3,990)     13,086        1,106
--------------------------------------------------------------------
Total operating
   revenues                    $23,581     $24,662      $(8,509)
====================================================================
Percent change                     3.6%        3.9%        (1.3)%
--------------------------------------------------------------------

   Retail revenues of $512.8 million in 1999 increased $3.6 million, or 0.7
percent, from the prior year due primarily to an increase in the number of
retail customers served by the Company. Retail revenues for 1998 decreased $12.5
million, or 2.4 percent, when compared to 1997 due primarily to the recovery of
lower fuel costs. The price per ton of coal, which is the Company's primary fuel
source, was lower in 1998 as the costs related to prior year coal contract
renegotiations were fully amortized and a major coal contract price was reduced.
See Note 5 to the financial statements under "Fuel Committments" for further
information.

   The 1999 increase in regulatory cost recovery and other retail revenues over
1998 is primarily attributable to the recovery of increased purchased power
capacity costs. The 1998 decrease in regulatory cost recovery and other retail
revenues over 1997 is primarily attributable to decreased fuel costs as
mentioned previously. Regulatory cost recovery and other includes recovery
provisions for fuel expense and the energy component of purchased power costs;
energy conservation costs; purchased power capacity costs; and environmental
compliance costs. The recovery provisions generally equal the related expenses
and have no material effect on net income. See Notes 1 and 3 to the financial
statements under "Revenues and Regulatory Cost Recovery Clauses" and
"Environmental Cost Recovery," respectively, for further information.

   Sales for resale were $128.5 million in 1999, an increase of $24 million, or
23 percent, over 1998 primarily due to additional energy sales to affiliated
companies, which is discussed below. 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:

                             1999         1998          1997
                     ----------------------------------------
                                     (in thousands)
Capacity                  $19,792      $22,503       $24,899
Energy                     20,251       14,556        18,160
-------------------------------------------------------------
Total                     $40,043      $37,059       $43,059
=============================================================

   Declining capacity revenues are due primarily to the decline in net plant
investment related to these sales. In addition, the decline in 1999 reflects a
reduction in the authorized rate of return on the equity component of the
investment.

   Sales to affiliated companies vary from year to year depending on demand and
the availability and cost of generating resources at each company. These sales
have little impact on earnings.

                                     II-116
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1999 Annual Report


   Other operating revenues decreased in 1999 and increased in 1998 due
primarily to adjustments to reflect differences between recoverable costs and
the amounts actually reflected in current rates. See Notes 1 and 3 to the
financial statements under "Revenues and Regulatory Cost Recovery Clauses" and
"Environmental Cost Recovery," respectively, for further discussion.

Energy Sales

   Kilowatt-hour sales for 1999 and the percent changes by year were as follows:

                         KWH               Percent Change
                     ------------- -------------------------------
                         1999         1999     1998       1997
                     ------------- -------------------------------
                       (millions)

Residential                 4,471      0.8%     7.7%      (1.0)%
Commercial                  3,223      3.6      7.4        3.2
Industrial                  1,846      0.7     (3.7)       5.3
Other                          19      0.0      4.7        1.6
                     -------------
Total retail                9,559      1.7      5.2        1.6
Sales for resale
   Non-affiliates           1,562     16.4    (12.4)      (0.2)
   Affiliates               2,512     42.9    107.3       19.5
                     -------------
Total                      13,633      9.0     10.5        2.5
==================================================================

   In 1999, total retail energy sales increased due to increases from 1998 in
the number of residential, commercial and industrial customers. Total energy
sales increased in 1998 when compared to 1997 due to higher temperatures when
compared to the milder-than-normal temperatures in 1997 and due to increases in
the number of residential and commercial customers. The decrease in industrial
energy sales in 1998 when compared to 1997 primarily reflects the shut down of a
major industrial customer's plant site and temporary production delays of other
industrial customers. See "Future Earnings Potential" for information on the
Company's initiatives to remain competitive and to meet conservation goals set
by the Florida Public Service Commission (FPSC).

   An increase in energy sales for resale to non-affiliates of 16.4 percent in
1999 when compared 1998 and a decrease of 12.4 percent in 1998 when compared to
1997 are 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 as mentioned previously.

Expenses

Total operating expenses in 1999 increased $26.8 million, or 5.1 percent, over
the amount recorded in 1998 due primarily to higher fuel and purchased power
expenses, offset by lower other operation expenses. In 1998, total operating
expenses increased $26.5 million, or 5.3 percent, from 1997. The increase was
due primarily to higher fuel, purchased power, and maintenance expenses offset
by lower other operation expenses.

   Fuel expenses in 1999, when compared to 1998, increased $11.5 million, or 5.9
percent. In 1998, fuel expenses increased $16.6 million, or 9.2 percent, when
compared to 1997. The increases were the result of increased generation
resulting from a higher demand for energy, while average fuel costs decreased as
noted below.

   Purchased power expenses increased in 1999 by $13.2 million, or 30.2 percent,
over 1998 and purchased power expenses for 1998 increased over 1997 by $6.9
million, or 18.8 percent, due to a higher demand for energy in both years.

   The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:

                                          1999       1998       1997
                                      -------------------------------
Total generation
   (millions of kilowatt-hours)         13,095     11,986     10,435
Sources of generation
   (percent)
   Coal                                   97.4       98.0       99.6
   Oil and gas                             2.6        2.0        0.4
Average cost of fuel per net
   kilowatt-hour generated
   (cents)--                              1.60       1.69       1.99
---------------------------------------------------------------------

   Other operation expenses decreased $4.3 million, or 3.6 percent, in 1999 from
the 1998 level and $7.3 million, or 5.7 percent, in 1998 from the 1997 level due
to a decrease in the amortization costs of prior year payments related to
renegotiations of coal supply contracts. The 1998 decrease was partially offset
by higher implementation costs of a new customer accounting system, increased
costs related to the Year 2000 program and an increase in the accrual to the
accumulated provision for property damage.



                                       II-117


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 1999 Annual Report


   Depreciation and amortization expense increased $5.5 million, or 9.2 percent,
in 1999 when compared to 1998 due primarily to a reduction in the amortization
of gains from the 1998 sale of emission allowances.

   Maintenance expenses in 1998 increased by $9.3 million, or 19.4 percent, over
1997 due primarily to scheduled maintenance at Plant Crist and Plant Smith and
increased transmission and distribution maintenance.

   Interest on long-term debt in 1999 increased $1.7 million, or 8.4 percent,
when compared to 1998 due primarily to two first mortgage bonds maturing in 1998
and being replaced by senior notes at a slightly higher interest rate, and the
issuance of $50 million of senior notes in August 1999. In 1998, interest on
long-term debt decreased $2.0 million, or 9.1 percent, from 1997 mostly due to a
decrease in interest expense on pollution control bonds refinanced in 1997 and
two long-term bank notes that matured in 1998. This decrease was partially
offset by an increase in interest due to the replacement in 1998 of the two
maturing first mortgage bonds with senior notes at a slightly higher interest
rate.

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

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 potentially less
regulated and more competitive environment.

   Gulf Power currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
northwest Florida. Prices for electricity provided by the Company to retail
customers are set by the FPSC.

   Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the Company's service area. In early 1999, the FPSC
Staff and the Company became involved in serious 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 would receive two-thirds of any revenue within
the ranges and the Company would retain one-third. For calendar year 2000, the
Company's retail base rate revenues in excess of $352 million up to $368 million
will be shared between the Company and its retail customers on the
one-third/two-thirds basis. Retail base rate revenues above $368 million for
calendar year 2000 will be refunded to the Company's customers. These set ranges
increase gradually until the expiration of the plan. The Sharing Plan will be in
place until the earlier of the in-service date of Smith Unit 3 or December 31,
2002. The parties could not agree on the appropriate Return on Equity (ROE).
Consequently, the Company filed a request to prospectively reduce its authorized
ROE range from 11 to 13 percent to 10.5 to 12.5 percent in order to help ensure
that the FPSC would approve the stipulation. Both the stipulation and the ROE
request were approved by the Commission on October 5, 1999, with an effective
date of November 4, 1999.

   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 Company is positioning the business to meet the challenge of
this major change in the traditional practice of selling electricity. The Energy
Act allows independent power producers (IPPs) to access the Company's



                                       II-118

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 1999 Annual Report


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. The Company
has and will continue to evaluate opportunities to partner and participate in
profitable cogeneration projects. In 1998, partnering with one of the Company's
largest industrial customers, construction was completed on 15 megawatts of
Company-owned cogeneration on the customer's plant site. Also, electricity sales
for resale rates are being driven down by wholesale transmission access and
numerous potential new energy suppliers, including power marketers and brokers.
The Company is aggressively working to maintain and expand its share of
wholesale sales in the southeastern power markets.

   Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry continues to
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Florida, none have been enacted to date. Enactment would require numerous issues
to be resolved, including significant ones relating to transmission pricing and
recovery of any stranded investments. The inability of the Company to recover
its investments, including the regulatory assets described in Note 1 to the
financial statements, could have a material adverse effect on financial
condition and results of operation. The Company is attempting to minimize or
reduce its cost exposure.

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

   In 1996, the FPSC approved a new optional Commercial/Industrial Service Rider
(CISR), which is applicable to the rate schedules for the Company's largest
existing and potential customers who are able to show they have viable
alternatives to purchasing the Company's energy services. The CISR, approved as
a pilot program, provides the flexibility needed to enable the Company to offer
its services in a more competitive manner to these customers. The publicity of
the CISR ruling, increased competitive pressures, and general awareness of
customer choice pilots and proposals across the country have stimulated interest
on the part of customers in custom tailored offerings. The Company has
participated in one-on-one discussions with many of these customers, and has
negotiated and executed two Contract Service Agreements within the CISR pilot
program. The pilot program ends in September of 2000 and the company is
currently reviewing its options.

   Every five years the FPSC establishes numeric demand side management goals.
The Company proposed numeric goals for the ten-year period from 2000 to 2009.
The proposed goals consisted of the total, cost-effective winter and summer peak
demand (kilowatts) and annual energy (kilowatt-hour) savings reasonably
achievable from demand side management for the residential and
commercial/industrial classes. The Company submitted its 2000 Demand Side
Management Plan to the FPSC on December 29, 1999. The plan describes the
Company's proposed programs it will employ to reach the numeric goals. The plan
relies heavily on innovative pricing and energy efficient construction. The FPSC
is expected to issue its final order on the Company's 2000 Demand Side
Management Plan in mid-April 2000.

   On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
the formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including Southern Company, are required
to make a filing by October 15, 2000. The filing must contain either a proposal
for RTO participation or a description of the efforts made to participate in an
RTO, the reasons for non-participation, any obstacles to participation, and any


                                      II-119

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 1999 Annual Report


plans for further work toward participation. The RTOs that are proposed in the
filings should be operational by December 15, 2001. Southern Company is
evaluating this issue and formulating its response. The outcome of this matter
cannot now be determined.

   Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters." Also, Florida legislation adopted in 1993 that provides
for recovery of prudent environmental compliance costs is discussed in Note 3 to
the financial statements under "Environmental Cost Recovery."

   The Company is subject to the provisions of 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.

Exposure to Market Risks

Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statements as incurred. At December 31, 1999, exposure from these activities was
not material to the Company's financial position, results of operations, or cash
flows. Also, based on the Company's overall interest rate exposure at December
31, 1999, a near-term 100 basis point change in interest rates would not
materially affect the Company's financial statements.

New Accounting Standards

The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 1, 2001. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. Adoption of this statement is not expected to have a
material impact on the Company's financial statements.

Year 2000 Challenge

The work undertaken by the Company to ensure that all critical computer systems
and other date sensitive devices would function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area of the Company. There were no reports
of significant events regarding third parties that impacted revenues or
expenses.

   The Company's original projected total costs for Year 2000 readiness were
approximately $5 million. Final projected costs were also $5 million with no
material costs remaining to be spent in 2000. From its inception through
December 31, 1999, the Year 2000 program costs, recognized primarily as expense,
amounted to $5 million, of which $2 million was recorded in 1999.

FINANCIAL CONDITION

Overview

The Company's financial condition continues to be very solid. During 1999, gross
property additions were $69.8 million. Funds for the property additions were
provided by operating activities. See the Statements of Cash Flows for further
details.

Financing Activities

In 1999, the Company sold $50 million of senior notes and long-term bank notes
totaling $27 million were retired. The remaining proceeds from this issuance
were used to reduce short-term borrowing requirements. See the Statements of
Cash Flows for further details.

   Composite financing rates for the years 1997 through 1999 as of year end were
as follows:


                                       II-120

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 1999 Annual Report


                                       1999      1998      1997
                                    -----------------------------
Composite interest rate on
  long-term debt                        6.0%      6.1%      5.9%
Composite rate on
  trust preferred securities            7.3%      7.3%      7.6%
Composite preferred stock
  dividend rate                         5.1%      5.1%      6.1%
-----------------------------------------------------------------

   The composite interest rate on long-term debt decreased in 1999 primarily due
to lower interest rates on variable rate pollution control bonds.

Capital Requirements for Construction

The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $428 million for the three years
beginning in 2000 ($106 million in 2000, $232 million in 2001, and $90 million
in 2002). These amounts include $198.8 million for the years 2000 through 2002
for the estimated cost of a 574 megawatt combined cycle gas 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 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: business conditions; environmental
regulations; load projections; the cost and efficiency of construction labor,
equipment, and materials; and the cost of capital. In addition, there can be no
assurance that costs related to capital expenditures will be fully recovered.

Other Capital Requirements

The Company will continue to retire higher-cost debt and preferred securities
and replace these securities with lower-cost capital as market conditions and
terms of the instruments permit.

Environmental Matters

In November 1990, the Clean Air Act 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 are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.

   Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $300
million for Southern Company, including approximately $42 million for Gulf
Power.

   For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as required to meet Phase II limits and ozone non-attainment requirements.
Compliance for Phase II and initial ozone non-attainment requirements increased
total estimated construction expenditures by approximately $105 million. Phase
II compliance is not expected to have a material impact on Gulf Power.

   Following adoption of legislation in April of 1992 allowing electric
utilities in Florida to seek FPSC approval of their Clean Air Act Compliance
Plans, Gulf Power filed its petition for approval. The FPSC approved the
Company's plan for Phase I compliance, deferring until a later date approval of
its Phase II Plan.

   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
makes the standards significantly more stringent. In September 1998, the EPA
issued the final regional nitrogen oxide reduction rule to the states for
implementation. The final rule affects 22 states, including Alabama and Georgia.


                                       II-121

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report


See Note 6 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's July 1997 standards and the September 1998 rule are being
challenged in the courts by several states and industry groups. Implementation
of the final state rules for these three initiatives could require substantial
further reductions in nitrogen oxide and sulfur dioxide emissions from
fossil-fired generating facilities and other industries in these states.
Additional compliance costs and capital expenditures resulting from the
implementation of these rules and standards cannot be determined until the
results of legal challenges are known, and the states have adopted their final
rules.

   The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: nitrogen oxide emission control
strategies for ozone non-attainment areas; additional controls for hazardous air
pollutant emissions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.

   On November 3, 1999, the EPA brought a civil action in the U.S. District
Court against Alabama Power, Georgia Power, and the system service company. The
complaint alleges violations of the prevention of significant deterioration and
new source review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. See Note 6 to
the financial statements under "Joint Ownership Agreements" related to the
Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3. In
early 2000, the EPA filed a motion to amend its complaint to add the violations
alleged in its notice of violation, and to add Gulf Power, Mississippi Power,
and Savannah Electric as defendants.  The complaint and notice of violation are
similar to those brought against and issued to several other electric utilities.
These complaints and notices of violation allege that the utilities had failed
to secure necessary permits or install additional pollution equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. Southern Company believes that its integrated
utilities complied with applicable laws and the EPA's regulations and
interpretations in effect at the time the work in question took place. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

   Gulf Power 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.



                                       11-122

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report


Sources of Capital

At December 31, 1999, the Company had approximately $15.8 million of cash and
cash equivalents and $41.5 million of unused committed lines of credit with
banks to meet its short-term cash needs. Refer to the Statements of Cash Flows
for details related to the Company's financing activities. See Note 5 to the
financial statements under "Bank Credit Arrangements" for additional
information.

   The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.

   If the Company chooses to issue first mortgage bonds or preferred stock, it
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 1999 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information. Accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the Company's markets; potential business strategies -- including
acquisitions or dispositions of assets or internal restructuring -- that may be
pursued by the company; state and federal rate regulation; changes in or
application of environmental and other laws and regulations to which the company
is subject; political, legal and economic conditions and developments; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; and other
factors discussed in the reports -- including Form 10-K -- filed from time to
time by the Company with the Securities and Exchange Commission.





                                       11-123



<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Gulf Power Company 1999 Annual Report

-----------------------------------------------------------------------------------------------------------
                                                         1999                 1998                1997
-----------------------------------------------------------------------------------------------------------
                                                                       (in thousands)
<S>                                                      <C>                  <C>                 <C>
Operating Revenues:
Retail sales                                             $512,760             $509,118            $521,619
Sales for resale --
  Non-affiliates                                           62,354               61,893              63,697
  Affiliates                                               66,110               42,642              16,760
Other revenues                                             32,875               36,865              23,780
-----------------------------------------------------------------------------------------------------------
Total operating revenues                                  674,099              650,518             625,856
-----------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                    209,031              197,462             180,843
  Purchased power --
    Non-affiliates                                         46,332               29,369              11,938
    Affiliates                                             10,703               14,445              24,955
Other                                                     114,670              119,011             126,266
Maintenance                                                57,830               57,286              47,988
Depreciation and amortization                              64,589               59,129              57,874
Taxes other than income taxes                              51,782               51,462              51,775
-----------------------------------------------------------------------------------------------------------
Total operating expenses                                  554,937              528,164             501,639
-----------------------------------------------------------------------------------------------------------
Operating Income                                          119,162              122,354             124,217
Other Income (Expense):
Interest income                                             1,771                  931               1,203
Other, net                                                 (1,357)              (2,339)               (992)
-----------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                 119,576              120,946             124,428
-----------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt                                 21,375               19,718              21,699
Interest on notes payable                                   2,371                1,190                 891
Amortization of debt discount, premium and expense, net     1,989                2,100               2,281
Other interest charges                                      1,126                2,548               2,076
Distributions on preferred securities of subsidiary         6,200                6,034               2,804
-----------------------------------------------------------------------------------------------------------
Total interest charges and other, net                      33,061               31,590              29,751
-----------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                               86,515               89,356              94,677
Income taxes (Note 8)                                      32,631               32,199              33,450
-----------------------------------------------------------------------------------------------------------
Net Income                                                 53,884               57,157              61,227
Dividends on Preferred Stock                                  217                  636               3,617
-----------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock            $ 53,667             $ 56,521            $ 57,610
===========================================================================================================

The accompanying notes are an integral part of these statements.

</TABLE>


                                                                  II-124


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Gulf Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------------------------
                                                                        1999                 1998                1997
--------------------------------------------------------------------------------------------------------------------------
                                                                                      (in thousands)
<S>                                                                    <C>                  <C>                 <C>
Operating Activities:
Net income                                                             $  53,884            $  57,157           $  61,227
Adjustments to reconcile net income
 to net cash provided from operating activities --
     Depreciation and amortization                                        68,721               69,633              72,860
     Deferred income taxes and investment tax credits, net                (6,609)              (4,684)             (7,047)
     Other, net                                                            3,735                3,463               4,831
     Changes in certain current assets and liabilities --
        Receivables, net                                                 (10,484)              11,308                (692)
        Fossil fuel stock                                                 (5,656)              (4,917)              9,056
        Materials and supplies                                            (2,063)                 609               1,618
        Accounts payable                                                  (2,023)                 823               1,398
        Other                                                              7,030              (18,471)             22,296
--------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                              106,535              114,921             165,547
--------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                                 (69,798)             (69,731)            (54,289)
Other                                                                     (8,856)               5,990                 509
--------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                   (78,654)             (63,741)            (53,780)
--------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                 23,500              (15,500)             22,000
Proceeds --
   Other long-term debt                                                   50,000               50,000              60,930
   Preferred securities                                                        -               45,000              40,000
   Capital contributions from parent company                               2,294                  522                   -
Retirements --
   First mortgage bonds                                                        -              (45,000)            (25,000)
   Other long-term debt                                                  (27,074)              (8,326)            (56,902)
   Preferred stock                                                             -               (9,455)            (75,911)
Payment of preferred stock dividends                                        (271)                (792)             (5,370)
Payment of common stock dividends                                        (61,300)             (67,200)            (64,600)
Other                                                                       (246)              (4,167)             (3,014)
--------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities                                   (13,097)             (54,918)           (107,867)
--------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                   14,784               (3,738)              3,900
Cash and Cash Equivalents at Beginning of Period                             969                4,707                 807
--------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                             $  15,753             $    969           $   4,707
==========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
   Interest (net of amount capitalized)                                  $27,670              $28,044             $26,558
   Income taxes (net of refunds)                                          29,462               38,782              36,010
--------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-125

<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Gulf Power Company 1999 Annual Report

---------------------------------------------------------------------------------------------------------------------
Assets                                                                                 1999                     1998
---------------------------------------------------------------------------------------------------------------------
                                                                                              (in thousands)

<S>                                                                                <C>                         <C>
Current Assets:
Cash and cash equivalents                                                          $ 15,753                    $ 969
Receivables --
  Customer accounts receivable                                                       55,108                   49,067
  Other accounts and notes receivable                                                 4,325                    3,514
  Affiliated companies                                                                7,104                    3,442
  Accumulated provision for uncollectible accounts                                   (1,026)                    (996)
Fossil fuel stock, at average cost                                                   29,869                   24,213
Materials and supplies, at average cost (Note 1)                                     30,088                   28,025
Regulatory clauses under recovery (Note 1)                                           11,611                    9,737
Other                                                                                 5,354                    9,725
---------------------------------------------------------------------------------------------------------------------
Total current assets                                                                158,186                  127,696
---------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Notes 1 and 6)                                                        1,853,664                1,809,901
Less accumulated provision for depreciation                                         821,970                  784,111
---------------------------------------------------------------------------------------------------------------------
                                                                                  1,031,694                1,025,790
Construction work in progress                                                        34,164                   34,863
---------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                              1,065,858                1,060,653
---------------------------------------------------------------------------------------------------------------------
Other Property and Investments                                                        1,481                      588
---------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8)                                    25,264                   25,308
Prepaid pension costs (Note 2)                                                       17,734                   13,770
Debt expense, being amortized                                                         2,526                    2,565
Premium on reacquired debt, being amortized                                          17,360                   18,883
Other                                                                                20,086                   18,438
---------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                              82,970                   78,964
---------------------------------------------------------------------------------------------------------------------
Total Assets                                                                     $1,308,495               $1,267,901
=====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>


                                                                  II-126
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Gulf Power Company 1999 Annual Report

----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                                    1999                     1998
----------------------------------------------------------------------------------------------------------------------
                                                                                               (in thousands)

<S>                                                                               <C>                     <C>
Current Liabilities:
Securities due within one year (Note 10)                                          $        -               $   27,000
Notes payable                                                                         55,000                   31,500
Accounts payable --
  Affiliated                                                                          14,878                   19,756
  Other                                                                               22,581                   23,697
Customer deposits                                                                     12,778                   12,560
Taxes accrued --
  Income taxes                                                                         4,889                        -
  Other                                                                                7,707                    7,432
Interest accrued                                                                       9,255                    5,184
Vacation pay accrued                                                                   4,199                    4,035
Other                                                                                  4,961                   10,051
----------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                            136,248                  141,215
----------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                         367,449                  317,341
----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8)                                           162,776                  166,118
Deferred credits related to income taxes (Note 8)                                     49,693                   52,465
Accumulated deferred investment tax credits                                           27,712                   29,632
Employee benefits provisions                                                          31,735                   28,594
Other                                                                                 21,333                   15,648
----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                         293,249                  292,457
----------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
 securities of subsidiary trusts holding company junior
 subordinated notes (See accompanying statements)                                     85,000                   85,000
----------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements)                                          4,236                    4,236
----------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                            422,313                  427,652
----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                        $1,308,495               $1,267,901
======================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>


                                                                  II-127

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Gulf Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------------------
                                                                    1999              1998             1999              1998
------------------------------------------------------------------------------------------------------------------------------
                                                                         (in thousands)                (percent of total)
Long-Term Debt:
First mortgage bonds --

       Maturity                           Interest Rates
       ---------                          -------------
      <S>                                <C>                   <C>               <C>                    <C>       <C>
       July 1, 2003                       6.125%                $ 30,000          $ 30,000
       November 1, 2006                   6.50%                   25,000            25,000
       January 1, 2026                    6.875%                  30,000            30,000
------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                        85,000            85,000
------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
       7.05% due August 15, 2004                                  50,000                 -
       7.50% due June 30, 2037                                    20,000            20,000
       6.70% due June 30, 2038                                    49,926            50,000
       Adjustable rate (5.72% at 1/1/99)
         due November 20, 1999                                         -            27,000
------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable                                    119,926            97,000
------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
       Pollution control revenue bonds --
         Collateralized with first mortgage bonds:
          5.25% to 6.30% due 2006-2026                            108,700           108,700
          Variable rate (3.70% at 1/1/00)
           due 2024                                                20,000            20,000
       Collateralized with other property:
         Variable rate (3.75% at 1/1/00)
           due 2022                                                40,930            40,930
------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                       169,630           169,630
------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net                          (7,107)           (7,289)
------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
  requirement -- $22.5 million)                                  367,449           344,341
Less amount due within one year (Note 10)                              -            27,000
------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year              367,449           317,341            41.8%             38.0%
------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
  Redeemable Preferred Securities: (Note 9)
$25 liquidation value --
  7.00%                                                           45,000            45,000
  7.625%                                                          40,000            40,000
------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $6.2 million)           85,000            85,000              9.7              10.2
------------------------------------------------------------------------------------------------------------------------------
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
Less amount due within one year                                        -                 -
------------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year                         4,236             4,236              0.5               0.5
------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
  Authorized and Outstanding -
    992,717 shares in 1999 and 1998                               38,060            38,060
  Paid-in capital                                                221,254           218,960
  Premium on preferred stock                                          12                12
Retained earnings (Note 11)                                      162,987           170,620
------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                                422,313           427,652             48.0              51.3
------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                            $878,998          $834,229           100.0%             100.0%
==============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>

                                                                  II-128

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Gulf Power Company 1999 Annual Report

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

                                                                                  Premium on
                                                     Common         Paid-In       Preferred      Retained
                                                      Stock         Capital         Stock        Earnings          Total
-----------------------------------------------------------------------------------------------------------------------------
                                                                               (in thousands)

<S>                                                  <C>            <C>                <C>        <C>              <C>
Balance at January 1, 1997                            $38,060        $218,437           $81        $179,180         $435,758
Net income after dividends on preferred stock               -               -             -          57,610           57,610
Cash dividends on common stock                              -               -             -         (64,600)         (64,600)
Other                                                       -               1           (69)             18              (50)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997                           38,060         218,438            12         172,208          428,718
Net income after dividends on preferred stock               -               -             -          56,521           56,521
Capital contributions from parent company                   -             522             -               -              522
Cash dividends on common stock                              -               -             -         (57,200)         (57,200)
Other                                                       -               -             -            (909)            (909)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                           38,060         218,960            12         170,620          427,652
Net income after dividends on preferred stock               -               -             -          53,667           53,667
Capital contributions from parent company                   -           2,294             -               -            2,294
Cash dividends on common stock                              -               -             -         (61,300)         (61,300)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                          $38,060        $221,254           $12        $162,987         $422,313
=============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-129


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1999 Annual Report


1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

Gulf Power Company is a wholly owned subsidiary of Southern Company, which is
the parent company of five integrated Southeast utilities, a system service
company, Southern Communications Services (Southern LINC), Southern Company
Energy Solutions, Southern Energy, Inc. (Southern Energy), Southern Nuclear
Operating Company (Southern Nuclear), and other direct and indirect
subsidiaries. The integrated Southeast utilities -- Alabama Power, Georgia
Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric
service in four states. Gulf Power Company provides electric service to the
northwest panhandle of Florida. Contracts among the integrated Southeast
utilities -- related to jointly owned generating facilities, interconnecting
transmission lines, and the exchange of electric power --are regulated by the
Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange
Commission (SEC). The system service company provides, at cost, specialized
services to Southern Company and subsidiary companies. Southern LINC provides
digital wireless communications services to the operating companies and also
markets these services to the public within the Southeast. Southern Company
Energy Solutions develops new business opportunities related to energy products
and services. Southern Nuclear provides services to Southern Company's nuclear
power plants. Southern Energy acquires, develops, builds, owns, and operates
power production and delivery facilities and provides a broad range of
energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States.

   Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Florida Public Service Commission
(FPSC). The Company follows generally accepted accounting principles and
complies with the accounting policies and practices prescribed by the FPSC and
the FERC. The preparation of financial statements in conformity with generally
accepted accounting principles requires the use of estimates, and the actual
results may differ from those estimates.

   Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.

Related-Party Transactions

The Company has an agreement with Southern Company Services, Inc. (a wholly
owned subsidiary of Southern 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, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $43 million, $40 million,
and $36 million during 1999, 1998, and 1997, respectively.

Regulatory Assets and Liabilities

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



                                       II-130
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1999 Annual Report


                                              1999          1998
                                        --------------------------
                                             (in thousands)
Deferred income tax debits                 $25,264      $ 25,308
Deferred loss on reacquired
  debt                                      17,360        18,883
Environmental remediation                    5,745         7,076
Vacation pay                                 4,199         4,035
Regulatory clauses under (over)
  recovery, net                              8,486         3,700
Accumulated provision for
  property damage                           (5,528)       (1,605)
Deferred income tax credits                (49,693)      (52,465)
Other, net                                  (1,255)         (480)
------------------------------------------------------------------
 Total                                     $ 4,578      $  4,452
==================================================================

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

Revenues and Regulatory Cost Recovery Clauses

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its service area located in northwest
Florida and to wholesale customers in the Southeast.

   The Company accrues revenues for service rendered but unbilled at the end of
each fiscal period. 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.

   Fuel costs are expensed as the fuel is used. The Company's retail electric
rates include provisions to periodically 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.

Depreciation and Amortization

Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.8 percent in 1999 and
1998 and 3.6 percent in 1997. The increase in 1998 is attributable to new
depreciation rates, which were approved by the FPSC in 1998. When property
subject to depreciation is retired or otherwise disposed of in the normal course
of business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Also, the provision for depreciation expense includes an amount
for the expected cost of removal of facilities.

Income Taxes

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

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction. The cost of
maintenance, repairs, and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property (exclusive of minor
items of property) is charged to utility plant.

Cash and Cash Equivalents

Temporary cash investments are considered cash equivalents. Temporary cash
investments are securities with original maturities of 90 days or less.


                                     II-131



<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


Financial Instruments

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

                                       Carrying          Fair
                                         Amount         Value
                                   ---------------------------
                                          (in thousands)
Long-term debt:
   At December 31, 1999                $367,449      $349,791
   At December 31, 1998                $344,341      $357,100
Capital trust preferred
securities:
   At December 31, 1999                 $85,000       $69,092
   At December 31, 1998                 $85,000       $89,400
--------------------------------------------------------------

   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 $1.8 million and $1.3 million
at December 31, 1999 and 1998, 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 storm 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, 1999 and 1998, the accumulated
provision for property damage was $5.5 million and $1.6 million, respectively.
In 1995, the FPSC approved the Company's request to increase the amount of its
annual accrual to the accumulated provision for property damage account from
$1.2 million to $3.5 million and approved 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, when the Company believes it is in a position to do so. The Company
accrued $5.5 million in 1999 and $6.5 million in 1998 to the accumulated
provision for property damage. The Company charged $1.6 million to the provision
account in 1999. Charges to the provision account during 1998 totaled $4.2
million, which included $3.4 million related to Hurricane Georges.

2.  RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. The Company provides certain medical
care and life insurance benefits for retired employees. Substantially all
employees may become eligible for these benefits when they retire. Trusts are
funded to the extent required by the Company's regulatory commissions. 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
                                    ---------------------------
                                          1999           1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $143,012      $130,794
Service cost                              4,490         4,107
Interest cost                             9,440         9,572
Benefits paid                            (6,862)       (6,663)
Actuarial loss (gain) and
      employee transfers                 (8,113)        5,202
---------------------------------------------------------------
Balance at end of year                 $141,967      $143,012
===============================================================

                                      II-132



<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


                                           Plan Assets
                                    ---------------------------
                                        1999          1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year          $212,934       $222,196
Actual return on plan assets            35,971          1,310
Benefits paid                           (6,862)        (6,663)
Employee transfers                        (558)        (3,909)
---------------------------------------------------------------
Balance at end of year                $241,485       $212,934
===============================================================

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

                                           1999          1998
---------------------------------------------------------------
                                          (in thousands)
Funded status                           $99,518       $ 69,922
Unrecognized transition
  obligation                             (4,323)        (5,043)
Unrecognized prior
  service cost                            4,495          4,869
Unrecognized net gain                   (81,956)       (55,978)
---------------------------------------------------------------
Prepaid asset recognized
  in the Balance Sheets                 $17,734        $13,770
===============================================================

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

                                1999         1998         1997
-----------------------------------------------------------------
Service cost                  $4,490     $  4,107     $  3,897
Interest cost                  9,440        9,572        9,301
Expected return on
  plan assets                (15,968)     (14,827)     (13,675)
Recognized net gain           (1,579)      (1,891)      (1,656)
Net amortization                (347)        (347)        (347)
-----------------------------------------------------------------
Net pension income          $(3,964)      $(3,386)    $ (2,480)
=================================================================

Postretirement Benefits

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

                                            Accumulated
                                        Benefit Obligations
                                    ---------------------------
                                           1999          1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year            $49,303       $39,669
Service cost                              1,087           946
Interest cost                             3,261         3,123
Benefits paid                            (1,177)       (1,068)
Actuarial (loss) gain and
  employee transfers                     (4,464)        3,614
Amendments                                    -         3,019
---------------------------------------------------------------
Balance at end of year                  $48,010       $49,303
===============================================================

                                           Plan Assets
                                    ---------------------------
                                         1999          1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $9,603        $9,455
Actual return on plan assets            1,525            54
Employer contributions                  1,245         1,162
Benefits paid                          (1,177)       (1,068)
---------------------------------------------------------------
Balance at end of year                $11,196        $9,603
===============================================================

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

                                       1999           1998
---------------------------------------------------------------
                                         (in thousands)
Funded status                         $(36,814)      $(39,700)
Unrecognized transition
  obligation                             4,723          5,079
Unrecognized prior
  service cost                           2,741          2,900
Unrecognized net loss                    2,620          8,187
Fourth quarter contributions               300              -
---------------------------------------------------------------
Accrued liability recognized
  in the Balance Sheets               $(26,430)      $(23,534)
===============================================================


                                     II-133

<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


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

                                    1999      1998      1997
---------------------------------------------------------------
Service cost                       $1,087     $  946    $  896
Interest cost                       3,261      3,123     2,845
Expected return on
      plan assets                    (794)      (717)     (641)
Transition obligation                 356        356       356
Prior service cost                    159        119         -
Recognized net loss                   264        128       184
---------------------------------------------------------------
Net postretirement cost            $4,333     $3,955    $3,640
===============================================================

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

                                       1999       1998
--------------------------------------------------------
Discount                               7.50%      6.75%
Annual salary increase                 5.00%      4.25%
Long-term return on plan
assets                                 8.50%      8.50%
--------------------------------------------------------

    An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.5 percent through the year 2005, and
remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1999 as follows (in thousands):

                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
Benefit obligation                    $3,627          $(3,086)
Service and interest costs              $320            $(269)
===============================================================

Work Force Reduction Programs

The Company recorded costs related to work force reduction programs of $0.2
million in 1999, $2.8 million in 1998, and $1.4 million in 1997. The Company has
also incurred its pro rata share for the costs of affiliated companies'
programs. The costs related to these programs were $0.6 million for 1999, $0.2
million for 1998, and $1.3 million for 1997. The Company has expensed all costs
related to these work force reduction programs.

3.   CONTINGENCIES AND REGULATORY
     MATTERS

Environmental Cost Recovery

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

   In January 1994, the FPSC approved the Company's initial petition under the
ECRC for recovery of environmental costs. Initially, recovery under the ECRC was
determined semi-annually. The FPSC approved annual recovery periods beginning
with the October 1996 through September 1997 period. As of January 1999, the
annual recovery period is on a calendar-year basis as approved by the FPSC in
May 1998. Recovery includes a true-up of the prior period and a projection of
the ensuing period. During 1999 and 1998, the Company recorded ECRC revenues of
$11.6 million and $8.0 million, respectively.

   At December 31, 1999, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $5.7 million. These
estimated costs are expected to be expended from 2000 through 2006. These
projects have been approved by the FPSC for recovery through the ECRC discussed
above. Therefore, the Company recorded $1.2 million in current assets and
current liabilities and $4.5 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 the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act



                                       II-134

<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The Clean Air Act authorizes civil penalties of up to $27,500
per day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.

   The EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. See Note 6
under "Joint Ownership Agreements" related to the Company's ownership interest
in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a
motion to amend its complaint to add the violations alleged in its notice of
violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as
defendants.  The complaint and notice of violation are similar to those brought
against and issued to several other electric utilities. These complaints and
notices of violation allege that the utilities had failed to secure necessary
permits or install additional pollution equipment when performing maintenance
and construction at coal burning plants constructed or under construction prior
to 1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place.

   An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

4.  CONSTRUCTION PROGRAM

The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $106 million in 2000, $232 million in 2001, and
$90 million in 2002. 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, 1999, significant purchase commitments were outstanding in
connection with the construction program. The Company has budgeted $198.8
million for the years 2000 through 2002 for the estimated cost of a 574 megawatt
combined cycle gas 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
will continue its construction program related to transmission and distribution
facilities and the upgrading and extension of the useful lives of generating
plants.

    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.

5.  FINANCING AND COMMITMENTS

General

Current projections indicate that funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from operations; the sale of additional long-term unsecured debt, pollution
control bonds, and preferred securities; bank notes; and capital contributions
from Southern Company. In addition, the Company may issue additional long-term
debt and preferred securities primarily for debt maturities and redemptions of
higher-cost securities.

Bank Credit Arrangements

At December 31, 1999, the Company had $41.5 million of lines of credit with
banks subject to renewal June 1 of each year, all of which remained unused. In
addition, the Company has two unused committed lines of credit totaling $61.9
million that were established for liquidity support of its variable rate
pollution control bonds. In connection with these credit lines, the Company has
agreed to pay commitment fees and/or to maintain compensating balances with the
banks. The compensating balances, which represent substantially all of the cash
of the Company except for daily working funds and like items, are not legally
restricted from withdrawal. In addition, the Company has bid-loan facilities
with seven major money center banks that total $130 million, of which $50
million was committed at December 31, 1999.



                                       11-135

<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


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.

Fuel 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. Total estimated long-term
obligations at December 31, 1999 were as follows:

   Year                                           Fuel
   ---------                                 ----------------
                                              (in millions)
   2000                                                  $89
   2001                                                   70
   2002                                                   86
   2003                                                   90
   2004                                                   91
   2005 - 2026                                           508
   ----------------------------------------------------------
   Total commitments                                    $934
   ==========================================================

   In 1988, the Company made an advance payment of $60 million to a coal
supplier under an arrangement to lower the cost of future coal purchased under
an existing contract. This payment was fully amortized to expense on a per ton
basis as of March 1998.

   In December 1995, the Company made another payment of $22 million to the same
coal supplier under an arrangement to lower the cost of future coal and/or to
suspend the purchase of coal under an existing contract for 25 months. This
payment was fully amortized to expense on a per ton basis as of March 1998.

   The amortization expense of these contract renegotiations was recovered
through the fuel cost recovery clause discussed under "Revenues and Regulatory
Cost Recovery Clauses" in Note 1.

Lease Agreements

In 1989, the Company and Mississippi Power jointly entered into a twenty-two
year operating lease agreement for the use of 495 aluminum railcars. In 1994, a
second lease agreement for the use of 250 additional aluminum railcars was
entered into for twenty-two years. Both of these leases are for the
transportation of coal to Plant Daniel. At the end of each lease term, the
Company has the option to renew the lease. In 1997, three additional lease
agreements for 120 cars each were entered into for three years, with a monthly
renewal option for up to an additional nine months.

   The Company, as a joint owner of Plant Daniel, is responsible for one half of
the lease costs. The lease costs are charged to fuel inventory and are allocated
to fuel expense as the fuel is used. The Company's share of the lease costs
charged to fuel inventories was $2.8 million in 1999 and $2.8 million in 1998.
The annual amounts for 2000 through 2004 are expected to be $2.1 million, $1.7
million, $1.7 million, $1.7 million, and $1.8 million, respectively, and after
2004 are expected to total $14.4 million.

6.  JOINT OWNERSHIP AGREEMENTS

The Company and Mississippi Power jointly own Plant Daniel, a steam-electric
generating plant located in Jackson County, Mississippi. In accordance with an
operating agreement, Mississippi Power acts as the Company's agent with respect
to the construction, operation, and maintenance of the plant.

   The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant
Scherer is a steam-electric generating plant located near Forsyth, Georgia. In
accordance with an 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.




                                       II-136
<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


   At December 31, 1999, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:

                                     Plant Scherer      Plant
                                       Unit No. 3       Daniel
                                      (coal-fired)   (coal-fired)
                                     -----------------------------
                                            (in thousands)
Plant In Service                        $185,714(1)     $231,041
Accumulated Depreciation                 $66,193        $113,687
Construction Work in Progress               $276          $2,621

Nameplate Capacity (2)
   (megawatts)                               205             500
Ownership                                     25%             50%
------------------------------------------------------------------

(1)  Includes net plant acquisition adjustment.
(2)  Total megawatt nameplate capacity:
       Plant Scherer Unit No. 3:  818
       Plant Daniel:  1,000

7.  LONG-TERM POWER SALES AGREEMENTS

The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity and energy 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 $19.8 million in 1999, $22.5 million in
1998, and $24.9 million in 1997. Declining capacity revenues are due primarily
to the decline in net plant investment related to these sales. In addition, the
decline in 1999 reflects a reduction in the authorized rate of return on the
equity component of the investment.

   Unit power from specific generating plants of Southern Company is currently
being sold to Florida Power Corporation (FPC), Florida Power & Light Company
(FP&L), Jacksonville Electric Authority (JEA), and the City of Tallahassee,
Florida. Under these agreements, 214 megawatts of net dependable capacity were
sold by the Company during 1999. Sales will decrease to 209 megawatts per year
in 2000 and remain at that level -- unless reduced by FP&L, FPC, and JEA for the
periods after 2000 with a minimum of three years notice -- until the expiration
of the contracts in 2010.

   Capacity and energy sales to FP&L, the Company's largest single customer,
provided revenues of $24.3 million in 1999, $22.3 million in 1998, and $25.4
million in 1997, or 3.6 percent, 3.4 percent, and 4.1 percent of operating
revenues, respectively.

8.  INCOME TAXES

At December 31, 1999, the tax-related regulatory assets to be recovered from
customers were $25.3 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, 1999,
the tax-related regulatory liabilities to be credited to customers were $49.7
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:

                                      1999         1998       1997
                                ------------------------------------
                                          (in thousands)
Total provision for income taxes:

Federal--
   Current                         $33,973      $31,746    $34,522
   Deferred --current year          16,776       18,485     19,297
            --reversal of
                prior years        (22,883)    (22,952)    (25,778)
--------------------------------------------------------------------
                                    27,866       27,279     28,041
--------------------------------------------------------------------
State--
   Current                           5,267        5,137      5,975
   Deferred --current year           2,474        2,745      2,868
            --reversal of
                prior years         (2,976)     (2,962)     (3,434)
--------------------------------------------------------------------
                                     4,765        4,920      5,409
--------------------------------------------------------------------
Total                              $32,631      $32,199    $33,450
====================================================================

   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:



                                       11-137

<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


                                                    1999        1998
                                           --------------------------
                                                (in thousands)
Deferred tax liabilities:
   Accelerated depreciation                     $168,662    $155,833
   Property basis differences                      6,000      20,330
   Other                                          18,272      17,645
---------------------------------------------------------------------
Total                                            192,934     193,808
---------------------------------------------------------------------
Deferred tax assets:
   Federal effect of state deferred taxes          9,293       9,509
   Postretirement benefits                         8,456       7,644
   Other                                          12,526      10,702
---------------------------------------------------------------------
Total                                             30,275      27,855
---------------------------------------------------------------------
Net deferred tax liabilities                     162,659     165,953
Less current portion, net                           (117)       (165)
---------------------------------------------------------------------
Accumulated deferred income
  taxes in the Balance Sheets                   $162,776    $166,118
=====================================================================

   Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation and amortization in the Statements of Income. Credits amortized in
this manner amounted to $1.9 million in 1999, $1.9 million in 1998, and $2.2
million in 1997. At December 31, 1999, all investment tax credits available to
reduce federal income taxes payable had been utilized.

   A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                      1999      1998     1997
                                    ----------------------------
Federal statutory rate                  35%       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)      (1)
Other, net                               -        (2)      (4)
----------------------------------------------------------------
Effective income tax rate               38%       36%      35%
================================================================

   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.

9.  COMPANY OBLIGATED MANDATORILY
    REDEEMABLE PREFERRED SECURITIES

In January 1997, Gulf Power Capital Trust I (Trust I), of which the Company owns
all of the common securities, issued $40 million of 7.625 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust I are
$41 million aggregate principal amount of the Company's 7.625 percent junior
subordinated notes due December 31, 2036.

   In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company
owns all of the common securities, issued $45 million of 7.0 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust II are
$46 million aggregate principal amount of the Company's 7.0 percent junior
subordinated notes due December 31, 2037.

   The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of payment obligations with respect to the preferred
securities of Trust I and Trust II. Trust I and Trust II are subsidiaries of the
Company, and accordingly are consolidated in the Company's financial statements.

10.  SECURITIES DUE WITHIN ONE YEAR

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

                                                1999        1998
                                           ----------------------
                                                 (in thousands)
Bond improvement fund requirement               $850     $   850
Less portion to be satisfied by
   certifying property additions                 850         850
-----------------------------------------------------------------
Cash requirement                                   -           -
Maturities of first mortgage bonds                 -           -
Current portion of other long-term
   debt                                            -      27,000
-----------------------------------------------------------------
Total                                           $  -     $27,000
=================================================================

   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


                                       11-138

<PAGE>
NOTES (continued)
Gulf Power Company 1999 Annual Report


cash, reacquiring bonds, or by pledging additional property equal to 1 and 2/3
times the requirement.

11.  COMMON STOCK DIVIDEND
     RESTRICTIONS

The Company's first mortgage bond indenture contains various common stock
dividend restrictions which remain in effect as long as the bonds are
outstanding. At December 31, 1999, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.

12.  QUARTERLY FINANCIAL DATA (Unaudited)

Summarized quarterly financial data for 1999 and 1998 are as follows:

                                                        Net Income
                                                    After Dividends
                         Operating     Operating       on Preferred
Quarter Ended             Revenues        Income              Stock
--------------------------------------------------------------------
                                     (in thousands)
March 1999                $134,506       $15,665            $ 4,799
June 1999                  166,815        29,253             13,226
September 1999             218,264        54,429             28,582
December 1999              154,514        19,815              7,060

March 1998                $140,950       $19,387            $ 6,853
June 1998                  177,130        33,232             13,364
September 1998             199,377        49,837             26,989
December 1998              133,061        19,898              9,315
--------------------------------------------------------------------

   The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.


                                       II-139

<PAGE>
<TABLE>
<CAPTION>
ELECTED FINANCIAL AND OPERATING DATA 1995-1999
Gulf Power Company 1999 Annual Report

-------------------------------------------------------------------------------------------------------------------------------
                                                          1999            1998            1997            1996            1995
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>             <C>             <C>             <C>             <C>
Operating Revenues (in thousands)                      674,099        $650,518        $625,856        $634,365        $619,077
Net Income after Dividends
  on Preferred Stock (in thousands)                    $53,667         $56,521         $57,610         $57,845         $57,154
Cash Dividends
  on Common Stock (in thousands)                       $61,300         $57,200         $64,600         $58,300         $46,400
Return on Average Common Equity (percent)                12.63           13.20           13.33           13.27           13.27
Total Assets (in thousands)                            308,495      $1,267,901      $1,265,612      $1,308,366      $1,341,859
Gross Property Additions (in thousands)                $69,798         $69,731         $54,289         $61,386         $63,113
-------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                    422,313        $427,652        $428,718        $435,758        $436,242
Preferred stock                                          4,236           4,236          13,691          65,102          89,602
Company obligated mandatorily
  redeemable preferred securities                       85,000          85,000          40,000               -               -
Long-term debt                                         367,449         317,341         296,993         331,880         323,376
-------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)          878,998        $834,229        $779,402        $832,740        $849,220
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                       48.0            51.3            55.0            52.3            51.4
Preferred stock                                            0.5             0.5             1.8             7.8            10.5
Company obligated mandatorily
  redeemable preferred securities                          9.7            10.2             5.1               -               -
Long-term debt                                            41.8            38.0            38.1            39.9            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                                    AA-             AA-             AA-              A+              A+
    Duff & Phelps                                          AA-             AA-             AA-             AA-              A+
Preferred Stock -
    Moody's                                                 a2              a2              a2              a2              a2
    Standard and Poor's                                     A-               A               A               A               A
    Duff & Phelps                                           A               A+              A+              A+               A
Unsecured Long-Term Debt -
    Moody's                                                 A2              A2              A2               -               -
    Standard and Poor's                                      A               A               A               -               -
    Duff & Phelps                                           A+              A+              A+               -               -
===============================================================================================================================
Customers (year-end):
Residential                                            315,240         307,077         300,257         291,196         283,421
Commercial                                              47,728          46,370          44,589          43,196          41,281
Industrial                                                 267             257             267             278             278
Other                                                      319             268             264             162             134
-------------------------------------------------------------------------------------------------------------------------------
Total                                                  363,554         353,972         345,377         334,832         325,114
===============================================================================================================================
Employees (year-end):                                    1,339           1,328           1,328           1,384           1,501
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                                                  II-140


<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Gulf Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------------------
                                                         1999            1998            1997            1996            1995
------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S>                                                 <C>              <C>            <C>             <C>             <C>
Residential                                         $ 277,311        $276,208       $ 277,609       $ 285,498       $ 276,155
Commercial                                            165,871         160,960         164,435         164,181         159,260
Industrial                                             67,404          69,850          77,492          78,994          81,606
Other                                                   2,174           2,100           2,083           2,056           1,993
------------------------------------------------------------------------------------------------------------------------------
Total retail                                          512,760         509,118         521,619         530,729         519,014
Sales for resale  - non-affiliates                     62,354          61,893          63,697          63,201          60,413
Sales for resale  - affiliates                         66,110          42,642          16,760          17,762          18,619
------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity              641,224         613,653         602,076         611,692         598,046
Other revenues                                         32,875          36,865          23,780          22,673          21,031
------------------------------------------------------------------------------------------------------------------------------
Total                                                $674,099        $650,518        $625,856        $634,365        $619,077
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential                                         4,471,118       4,437,558       4,119,492       4,159,924       4,014,142
Commercial                                          3,222,532       3,111,933       2,897,887       2,808,634       2,708,243
Industrial                                          1,846,237       1,833,575       1,903,050       1,808,086       1,794,754
Other                                                  19,296          18,952          18,101          17,815          17,345
------------------------------------------------------------------------------------------------------------------------------
Total retail                                        9,559,183       9,402,018       8,938,530       8,794,459       8,534,484
Sales for resale  - non-affiliates                  1,561,972       1,341,990       1,531,179       1,534,097       1,396,474
Sales for resale  - affiliates                      2,511,983       1,758,150         848,135         709,647         759,341
------------------------------------------------------------------------------------------------------------------------------
Total                                              13,633,138      12,502,158      11,317,844      11,038,203      10,690,299
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                              6.20            6.22            6.74            6.86            6.88
Commercial                                               5.15            5.17            5.67            5.85            5.88
Industrial                                               3.65            3.81            4.07            4.37            4.55
Total retail                                             5.36            5.41            5.84            6.03            6.08
Sales for resale                                         3.15            3.37            3.38            3.61            3.67
Total sales                                              4.70            4.91            5.32            5.54            5.59
Residential Average Annual
  Kilowatt-Hour Use Per Customer                       14,318          14,577          13,894          14,457          14,148
Residential Average Annual
  Revenue Per Customer                                $888.01         $907.35         $936.30         $992.17         $973.35
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                        2,188           2,188           2,174           2,174           2,174
Maximum Peak-Hour Demand (megawatts):
Winter                                                  2,085           2,040           1,844           2,136           1,732
Summer                                                  2,161           2,146           2,032           1,961           2,040
Annual Load Factor (percent)                             55.2            55.3            55.5            51.4            53.0
Plant Availability Fossil-Steam (percent):               87.2            87.6            91.0            91.8            84.0
------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                     89.8            89.2            87.1            87.8            86.8
Oil and gas                                               2.5             2.0             0.4             0.5             0.4
Purchased power -
  From non-affiliates                                     5.9             5.5             3.5             2.7             4.0
  From affiliates                                         1.8             3.3             9.0             9.0             8.8
------------------------------------------------------------------------------------------------------------------------------
Total                                                   100.0           100.0           100.0           100.0           100.0
==============================================================================================================================
</TABLE>





                                                                  II-141


<PAGE>



                           MISSISSIPPI POWER COMPANY

                                FINANCIAL SECTION


                                     II-142


<PAGE>

MANAGEMENT'S REPORT
Mississippi Power Company 1999 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 generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.

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

    The Company's system of internal accounting controls is evaluated on an
ongoing basis by the 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 directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors, and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of the
audit committee at any time.

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

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



/s/Dwight H. Evans
Dwight H. Evans
President and Chief Executive Officer

/s/Michael W. Southern
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer



February 16, 2000


                                      II-143


<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Mississippi Power Company:

We have audited the accompanying balance sheets and statements of capitalization
of Mississippi Power Company (a Mississippi corporation and a wholly owned
subsidiary of Southern Company) as of December 31, 1999 and 1998, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 1999. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

    In our opinion, the financial statements (pages II-152 through II-168)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 1999 and 1998, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.



/s/ Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000






                                       II-144
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 1999 Annual Report


RESULTS OF OPERATIONS

Earnings

Mississippi Power Company's 1999 net income after dividends on preferred stock
of $54.8 million remained relatively flat when compared to 1998. In 1998,
earnings were $55.1 million, up $1.1 million from the prior year. This change is
primarily attributable to higher retail and wholesale revenues.

Revenues

The following table summarizes the factors impacting operating revenues for the
past three years:

                                      Increase (Decrease)
                                        From Prior Year
                              ----------------------------------
                               1999         1998          1997
                              ----------------------------------
                                       (in thousands)
  Retail --
     Change in base
      rates (PEP and
      ECO Plan)            $   792      $    335       $ 3,177
     Sales growth            7,876         4,787           109
     Weather                (1,404)        7,091        (1,118)
     Fuel cost
      recovery
      and other             19,603        13,112           948
  --------------------------------------------------------------
  Total retail              26,867        25,325         3,116
  --------------------------------------------------------------
  Sales for resale --
     Non-affiliates          9,778       16,084          5,464
     Affiliates              1,161        8,142        (11,606)
  --------------------------------------------------------------
  Total sales for
     resale                 10,939       24,226         (6,142)
  Other operating
     revenues                   67        1,992          2,585
  --------------------------------------------------------------
  Total operating
     revenues              $37,873      $51,543        $ (441)
  ==============================================================
  Percent change               6.4%         9.5%         (0.1)%
  --------------------------------------------------------------

    Retail revenues of $469 million in 1999 increased 6.1 percent from 1998.
This increase resulted primarily from continued growth in the service area and a
true-up of the unbilled revenue estimate. Retail revenues for 1998 reflected a
6.1 percent increase over the prior year due to the continued growth in the
service area and the positive impact of weather on energy sales.

    Fuel revenues generally represent the direct recovery of fuel expense
including purchased power. Therefore, changes in recoverable fuel expenses are
offset with corresponding changes in fuel revenues and have no effect on net
income.

    Energy sales to non-affiliates include economy sales and amounts sold under
short-term contracts. Sales for resale to non-affiliates are influenced by those
utilities' own customer demand, plant availability, and the cost of their
predominant fuels.

    Included in sales for resale to non-affiliates are revenues from rural
electric cooperative associations and municipalities located in southeastern
Mississippi. Energy sales to these customers increased 10.2 percent in 1999 and
9.8 percent in 1998, with the related revenues rising 12.1 percent and 11.3
percent, respectively. The customer demand experienced by these utilities is
determined by factors very similar to Mississippi Power's. Revenues from other
sales outside the service area increased in 1999 and 1998 primarily due to power
marketing activities. These increases were offset by increases in purchased
power from non-affiliates and, as a result, had no significant effect on net
income.

    Sales to affiliated companies within the Southern electric system will vary
from year to year depending on demand and the availability and cost of
generating resources at each company. These sales have no material impact on
earnings.

    Below is a breakdown of kilowatt-hour sales for 1999 and the percent change
for the last three years:

                          1999              Percent Change
                       -----------   ------------------------------
                           KWH            1999    1998      1997
                          (in
                       millions)

 Residential             2,248             -       10.3%    (2.0)%
 Commercial              2,848            8.5       9.0      4.0
 Industrial              4,407           18.2      (6.4)     0.6
 Other                      40            0.8       -        2.6
 Total retail            9,543           10.4       2.0      0.9
 Sales for
    Resale --
     Non-affiliates      3,256            3.1       9.1      6.2
     Affiliates            540           (2.2)     15.2    (31.0)
                       ----------
 Total                  13,339            8.0       4.3      0.2
 ==================================================================


                                       II-145

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report


    Total retail sales increased 10.4 percent from 1998 primarily because of
continued growth in the service area, industrial customers' recovery from last
year's hurricane and a true-up of the unbilled revenue estimate. The unbilled
revenue true-up amounted to approximately 3.5 percent of the total increase.

    Residential sales decreased slightly in 1999 due to the mild weather in the
spring and winter periods, while commercial and industrial sales increased by
8.5 percent and 18.2 percent, respectively. Increased tourism and strong growth
impacted commercial sales, while industrial sales were impacted by increased
production by several larger industrial customers. Residential and commercial
sales increased in 1998 by 10.3 percent and 9.0 percent, respectively, due to
sales growth and higher than normal temperatures in the summer months. Sales to
industrial customers decreased by 6.4 percent primarily due to a large
industrial customer being shut down because of damages incurred from Hurricane
Georges.

    The Company anticipates continued growth in energy sales as the economy
improves within its service area. The casino industry and ancillary services,
such as lodging, food, transportation, etc., are some of the factors that may
influence the economy of the Company's service area. Also, energy demand is
expected to grow as a result of a larger and more fully employed population.

Expenses

Total operating expenses were $513 million in 1999 reflecting an increase of $33
million or 6.9 percent over the prior year. The increase was due primarily to
higher fuel costs. In 1998, total operating expenses increased by 10.6 percent
over the prior year due primarily to higher fuel expenses, higher maintenance
and higher other operation costs.

    Fuel costs are the single largest expense for the Company. Fuel expenses in
1999 increased 10.3 percent due to an increase in generation resulting from a
higher demand for energy. In 1999, expenses related to purchased power from
non-affiliates increased 18.3 percent, while expenses related to purchased power
from affiliates decreased 14.0 percent which, in total, resulted in a slight
increase when compared to 1998. Energy purchased for power marketing activities
was resold to non-affiliated third parties and had no significant effect on net
income. Sales and purchases among Mississippi Power and its affiliates will
vary from period to period depending on demand and the availability and
variable production cost at each generating unit in the Southern electric
system.

    In 1998, fuel costs increased because of a 3.1 percent increase in
generation and a higher average cost of fuel. The increased generation was due
to higher demand for energy across the Southern electric system. Expenses
related to purchased power from non-affiliates increased, and expenses related
to purchased power from affiliates decreased. Further, the higher demand for
energy resulted in higher purchased power costs from non-affiliates.

    The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:

                                     1999     1998      1997
                                   -------------------------
Total generation
   (millions of kilowatt
         hours)                    11,599   10,610     10,289
Sources of generation
   (percent) --
     Coal                              81       80         85
     Gas                               19       20         15
Average cost of fuel per net
   kilowatt-hour generated
         (cents) --                  1.65     1.62       1.54
--------------------------------------------------------------

    Other operation expenses increased 13.9 percent in 1999 primarily due to the
amortization of costs associated with the workforce reduction plan and higher
distribution expenses. In 1998, other operation expense increased 7.5 percent
due to continuing expenses related to a new customer service system,
modification of certain information systems for year 2000 readiness, and costs
related to workforce reduction programs. Maintenance expenses decreased 6.6
percent in 1999 due to reduced scheduled maintenance.  In 1999, depreciation and
amortization expenses increased 3.7 percent primarily due to growth in plant
investment. Comparisons of taxes other than income taxes for 1999 and 1998 show
increases of 4.2 percent and 4.4 percent, respectively, due to higher municipal
franchise taxes resulting from higher retail revenues. Interest expense
increased due to additional interest related to notes payable and interest
accrued on tax audit issues.

                                       II-146

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report


Effects of Inflation

Mississippi Power is subject to rate regulation and income tax laws that are
based on the recovery of historical costs. Therefore, inflation creates an
economic loss because the Company is recovering its costs of investments in
dollars that have less purchasing power. While the inflation rate has been
relatively low in recent years, it continues to have an adverse effect on the
Company because of the large investment in utility plant with long economic
lives. Conventional accounting for historical costs does not recognize this
economic loss or the partially offsetting gain that arises through financing
facilities with fixed-money obligations, such as long-term debt and preferred
securities. Any recognition of inflation by regulatory authorities is reflected
in the rate of return allowed.

Future Earnings Potential

The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors 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. See Note 2 to the financial statements under "Workforce
Reduction Programs" for information regarding the Company's workforce reduction
plan of 1997. The Company is also maximizing the utility of invested capital and
minimizing the need for additional capital by refinancing, managing the size of
its fuel stockpile, raising generating plant availability and efficiency, and
aggressively controlling the construction budget.

    The Company currently operates as a vertically integrated company 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) regulations. The ECO Plan is operated
independently of PEP. Compliance costs related to the Clean Air Act could affect
earnings if such costs cannot be recovered. The Company's 1999 ECO Plan was
approved, as filed, in 1999 and resulted in a slight decrease in customer
prices. The Company filed its 2000 ECO Plan in January, 2000 and, if approved as
filed, will result in a slight decrease in customer prices. Refer to Note 3 to
the financial statements under "Litigation and Regulatory Matters" for
additional information. The Clean Air Act and other important environmental
items are discussed later under "Environmental Matters".

    Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. These factors include weather,
competition, changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, and the rate of
economic growth in Mississippi Power's service area. Currently, the Company is
negotiating with certain of its wholesale customers a change in rates and has
committed to them that any agreement reached would be effective January 1, 2000.
At this time, no agreement has been reached and the ultimate amount of any rate
change cannot now be determined.

    The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows Independent Power Producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell energy generation
to other utilities. Also, wholesale transmission access and numerous potential
new energy suppliers, including power marketers and brokers, are driving down
electricity sales for resale rates. The Company is aggressively working to
maintain and expand its share of wholesale sales in the southeastern power
markets.

    Although the Energy Act does not permit retail transmission access, it was a
major catalyst for the current restructuring and consolidation taking place


                                       II-147

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report


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. While restructuring initiatives are being discussed in Mississippi, none
have been enacted to date. Enactment would require numerous issues to be
resolved, including significant ones relating to transmission pricing and
recovery of any stranded investments. The inability of Mississippi Power to
recover its investment, including regulatory assets, could have a material
adverse effect on the financial condition of the Company.

    The Company is attempting to minimize or reduce its cost exposure.
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 Mississippi Power remains a low-cost producer and
provides quality service, the Company's retail energy sales growth could be
limited, and this could significantly erode earnings. The Company is subject to
the provisions of Financial Accounting Standards Board (FASB) Statement No. 71,
Accounting for the Effects of Certain Types of Regulation. In the event that a
portion of the Company's operation is no longer subject to these provisions, the
Company would be required to write off related regulatory assets and liabilities
that are not specifically recoverable, and determine if any other assets have
been impaired. See Note 1 to the financial statements under "Regulatory Assets
and Liabilities" for additional information.

    On December 20, 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. To facilitate the
development of RTOs, the FERC will convene regional conferences for utilities,
customers, and other members of the public to discuss the formation of RTOs. In
addition to participating in the regional conferences, utilities owning
transmission systems, including the Company, are required to make a filing by
October 15, 2000. The filing must contain either a proposal for RTO
participation or a description of the efforts made to participate in an RTO, the
reasons for non-participation, any obstacles to participation, and any plans for
further work toward participation. The RTOs that are proposed in the filings
should be operational by December 15, 2001. The Company is evaluating the issue
and formulating its response. The outcome of this matter cannot now be
determined.

Exposure to Market Risks

Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statements as incurred. At December 31, 1999, exposure from these activities was
not material to the Company's financial position, results of operation, or cash
flow. Also, based on the Company's overall interest rate exposure at December
31, 1999, a near-term 100 basis point change in interest rates would not
materially affect the financial statements.

New Accounting Standard

The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 1, 2001. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings and other comprehensive income.

Year 2000

Year 2000 Challenge

The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area of the Company. There were no reports
of significant events regarding third parties that impacted revenues or
expenses.

    For the Company, original projected total costs for Year 2000 readiness were
approximately $5 million. These costs include labor necessary to identify, test,
and renovate affected devices and systems, and costs for reporting requirements
to state and federal agencies. From its inception through December 31, 1999, the


                                       II-148

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report


Year 2000 program costs, recognized primarily as expense, amounted to
approximately $5 million.

FINANCIAL CONDITION

Overview

The principal change in Mississippi Power's financial condition during 1999 was
the addition of approximately $76 million to utility plant. Funding for these
additions and other capital requirements were derived primarily from operations.
The Statements of Cash Flows provide additional details.

Financing Activity

In 1999, the Company sold $9.4 million of pollution control bonds. Additionally,
the Company retired and reissued unsecured debt of $50 million. See the
Statements of Cash Flows for further details.

    Composite financing rates have remained relatively flat for the years 1997
through 1999. As of year-end for each year respectively, the composite rates
were as follows:

                                    1999     1998     1997
                                 ----------------------------
 Composite interest rate on
     long-term debt                 6.19%    6.14%    6.16%

 Composite preferred stock
     dividend rate                  6.33%    6.33%    6.33%

 Composite interest rate on
     preferred securities           7.75%    7.75%    7.75%
 ------------------------------------------------------------

    In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the
Company to design and construct, as agent for Escatawpa, a 1,064 megawatt
natural gas combined cycle facility. It is anticipated that the total project
will cost approximately $406 million, and upon project completion in mid 2001,
the Company intends to lease the facility for an initial term of approximately
10 years. It is anticipated that the annual lease payments will approximate $32
million during the initial term.

Capital Structure

At year-end 1999, the Company's ratio of common equity to total capitalization,
excluding long-term debt due within one year, decreased from 52.1 percent in
1998, to 50.2 percent.

Capital Requirements for Construction

The Company's projected construction expenditures for the next three years total
$199 million ($84 million in 2000, $54 million in 2001, and $61 million in
2002). The major emphasis within the construction program will be on the upgrade
of existing facilities.

    Revisions to projected construction expenditures may be necessary because of
factors such as changes in business conditions, revised load projections, the
availability and cost of capital, changes in environmental regulations, and
alternatives such as leasing.

Other Capital Requirements

In addition to the funds required for the Company's construction program,
approximately $80.1 million will be required by the end of 2002 for present
sinking fund requirements and maturities of long-term debt. Mississippi Power
plans to continue, when economically feasible, to retire higher cost debt and
preferred stock and replace these obligations with lower-cost capital if market
conditions permit.

Environmental Matters

On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action in the U.S. District Court against Alabama Power Company, Georgia Power
Company and the system service company. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in Alabama
and Georgia. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The EPA concurrently issued to the integrated
Southeast utilities a notice of violation related to 10 generating facilities,
which includes the five facilities mentioned previously, and the Company's
plants Watson and Greene County. In early 2000, the EPA filed a motion to amend
its complaint to add the violations alleged in its notice of violation, and to
add Gulf Power, Mississippi Power, and Savannah Electric as defendants.

                                       II-149



<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report


The complaint and notice of violation are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly the Company's
financial condition unless such costs can be recovered through regulated rates.

    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 Mississippi Power and other subsidiaries of Southern Company. Specific
reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired
generating plants were required in two phases. Phase I compliance began in 1995
and initially affected 28 generating plants in the Southern electric system. As
a result of Southern Company's compliance strategy, an additional 22 generating
units were brought into compliance with Phase I requirements. Phase II
compliance started in 2000, and all fossil-fired generating plants are now
affected.

    Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $65
million for Mississippi Power.

    For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. 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.
Compliance for Phase II and initial ozone non-attainment requirements increased
total estimated construction expenditures by approximately $105 million. Phase
II compliance is not expected to have a material impact on Mississippi Power.

    Mississippi Power'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.
Mississippi Power'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 provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, there can be no assurance that all Clean Air Act costs will
be recovered.

    In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision made the standards significantly
more stringent. In September 1998, the EPA issued the final regional nitrogen
oxide rules to the states for implementation. The final rules affect 22 states
that at present does not include Mississippi. The EPA is presently evaluating
whether or not to bring an additional 15 states under this regional haze rule.
Mississippi is one of those new 15 states. The EPA's July 1997 standards and the
September 1998 rule are being challenged in the courts by several states and
industry groups. Implementation of the final state rules could require
substantial further reductions in nitrogen oxide emissions from fossil-fired
generating facilities and other industry in these states. Implementation of the
standards could result in significant additional compliance costs and capital
expenditures that cannot be determined until the results of legal challenges are
known, and the states have adopted their final rules.

    The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: emission control strategies for ozone
non-attainment areas; additional controls for hazardous air pollutant emissions;
and hazardous waste disposal requirements. The impact of any new standards will
depend on the development and implementation of applicable regulations.


                                       II-150


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report


    The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. Upon identifying potential sites, the Company conducts
studies, when possible, to determine the extent of any required cleanup costs.
Should remediation be determined to be probable, reasonable estimates of costs
to clean up such sites are developed and recognized in the financial statements.
A currently owned site where manufactured gas plant operations were located
prior to the Company's ownership was substantially remediated in 1999. See Note
3 to the financial statements under "Environmental Compliance Overview Plan" for
additional information.

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

    Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if any
-- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for lawsuits alleging damages
caused by electromagnetic fields or other environmental concerns. The likelihood
or outcome of such potential lawsuits cannot be determined at this time.

Sources of Capital

To meet short-term cash needs and contingencies, the Company had at December 31,
1999 approximately $173 thousand of cash and cash equivalents and approximately
$104.3 million of unused committed credit agreements. The Company had $57.5
million of short term notes payable outstanding at year end 1999.

    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
issuances 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 issued unsecured debt in 1998. In this regard,
Mississippi Power sought and obtained stockholder approval in 1998 to amend its
corporate charter eliminating restrictions on the amounts of unsecured
indebtedness the Company may incur.

    Mississippi Power is required to meet certain coverage requirements
specified in its mortgage indenture and corporate charter to issue new first
mortgage bonds and preferred stock. The Company's coverage ratios are high
enough to permit, at present interest rate levels, any foreseeable security
sales. The amount of securities which the Company will be permitted to issue in
the future will depend upon market conditions and other factors prevailing at
that time.

Cautionary Statement Regarding Forward-Looking
Information

This annual report, including the foregoing Management's Discussion and
Analysis, contains forward-looking and historical information. The Company
cautions that there are various important factors that could cause actual
results to differ materially from those indicated in the forward-looking
information; accordingly, there can be no assurance that such indicated results
will be realized. These factors include legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry; the
extent and timing of the entry of additional competition in the Company's
markets; potential business strategies -- including acquisitions or dispositions
of assets or internal restructuring -- that may be pursued by the Company; state
and federal rate regulation; changes in or application of environmental and
other laws and regulations to which the Company is subject; political, legal and
economic conditions and developments; financial market conditions and the
results of financing efforts; changes in commodity prices and interest rates;
weather and other natural phenomena; and other factors discussed in the reports
(including Form 10-K) filed from time to time by the Company with the SEC.



                                       II-151


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Mississippi Power Company 1999 Annual Report

----------------------------------------------------------------------------------------------------------------------
                                                                  1999                 1998                1997
----------------------------------------------------------------------------------------------------------------------
                                                                                  (in thousands)
<S>                                                                <C>                  <C>               <C>
Operating Revenues:
Retail sales                                                        $469,434             $442,567            $417,242
Sales for resale --
  Non-affiliates                                                     131,004              121,225             105,141
  Affiliates                                                          19,446               18,285              10,143
Other revenues                                                        13,120               13,054              11,062
----------------------------------------------------------------------------------------------------------------------
Total operating revenues                                             633,004              595,131             543,588
----------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                               172,686              156,539             142,059
  Purchased power --
    Non-affiliates                                                    40,080               33,872              14,536
    Affiliates                                                        31,007               36,037              37,794
  Other                                                              125,291              109,993             102,365
Maintenance                                                           47,085               50,404              47,302
Depreciation and amortization                                         49,206               47,450              45,574
Taxes other than income taxes                                         47,893               45,965              44,034
----------------------------------------------------------------------------------------------------------------------
Total operating expenses                                             513,248              480,260             433,664
----------------------------------------------------------------------------------------------------------------------
Operating Income                                                     119,756              114,871             109,924
Other Income:
Interest income                                                          273                  947                 857
Other, net                                                             1,675                2,498               2,368
----------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                            121,704              118,316             113,149
----------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt                                            20,455               20,567              19,856
Interest on notes payable                                              2,750                  943                  96
Amortization of debt discount, premium and expense, net                1,432                1,446               1,577
Other interest charges                                                 3,332                  790                 574
Distributions on preferred securities of subsidiary                    2,796                2,796               2,369
----------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                                 30,765               26,542              24,472
----------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                          90,939               91,774              88,677
Income taxes                                                          34,117               34,664              31,380
----------------------------------------------------------------------------------------------------------------------
Net Income                                                            56,822               57,110              57,297
Dividends on Preferred Stock                                           2,013                2,005               3,287
----------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock                       $ 54,809             $ 55,105            $ 54,010
======================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>

                                                                  II-152

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Mississippi Power Company 1999 Annual Report

-------------------------------------------------------------------------------------------------------------------------------
                                                                           1999                 1998                1997
-------------------------------------------------------------------------------------------------------------------------------

                                                                                         (in thousands)
<S>                                                                         <C>                  <C>                 <C>
Operating Activities:
Net income                                                                  $  56,822            $  57,110           $  57,297
Adjustments to reconcile net income
  to net cash provided from operating activities --
       Depreciation and amortization                                           53,427               51,517              49,661
       Deferred income taxes and investment tax credits, net                   (4,143)              11,620              (1,809)
       Other, net                                                               5,531              (12,175)              3,206
       Changes in certain current assets and liabilities --
          Receivables, net                                                    (39,304)              (5,486)             (8,583)
          Fossil fuel stock                                                    (9,379)              (5,767)              1,517
          Materials and supplies                                               (1,903)                 717               1,631
          Accounts payable                                                      1,391                 (389)              8,357
          Other                                                                14,206               (4,061)              3,980
-------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                                    76,648               93,086             115,257
-------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                                      (75,888)             (68,231)            (55,375)
Other                                                                           1,009                 (324)               (489)
-------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                        (74,879)             (68,555)            (55,864)
-------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                      44,500               13,000                   -
Proceeds --
   Other long-term debt                                                        59,400              103,520                   -
   Preferred securities                                                             -                    -              35,000
   Preferred stock                                                                  -                    -                   -
   Capital contributions from parent company                                    2,028                   85                   -
Retirements --
   First mortgage bonds                                                             -              (75,000)                  -
   Other long-term debt                                                       (50,456)             (13,020)                (10)
   Preferred stock                                                                  -                  (87)            (42,518)
Payment of preferred stock dividends                                           (2,013)              (2,005)             (3,287)
Payment of common stock dividends                                             (56,100)             (51,700)            (49,400)
Other                                                                            (282)              (2,429)             (1,804)
-------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities                                         (2,923)             (27,636)            (62,019)
-------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                        (1,154)              (3,105)             (2,626)
Cash and Cash Equivalents at Beginning of Period                                1,327                4,432               7,058
-------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                                  $     173            $   1,327           $   4,432
===============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
   Interest (net of amount capitalized)                                       $25,486              $26,133             $22,297
   Income taxes (net of refunds)                                               39,729               26,847              33,450
-------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-153

<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report

---------------------------------------------------------------------------------------------------------------------
Assets                                                                                 1999                     1998
---------------------------------------------------------------------------------------------------------------------
                                                                                              (in thousands)

<S>                                                                                <C>                  <C>
Current Assets:
Cash and cash equivalents                                                        $      173               $    1,327
Receivables --
  Customer accounts receivable                                                       61,274                   37,871
  Other accounts and notes receivable                                                23,490                   12,495
  Affiliated companies                                                               16,097                   10,946
  Accumulated provision for uncollectible accounts                                     (697)                    (621)
Fossil fuel stock, at average cost                                                   25,797                   16,418
Materials and supplies, at average cost                                              20,638                   18,735
Other                                                                                10,013                   10,616
---------------------------------------------------------------------------------------------------------------------
Total current assets                                                                156,785                  107,787
---------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:

In service                                                                        1,601,399                1,553,112
Less accumulated provision for depreciation                                         626,841                  583,957
---------------------------------------------------------------------------------------------------------------------
                                                                                    974,558                  969,155
Construction work in progress                                                        68,721                   51,517
---------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                              1,043,279                1,020,672
---------------------------------------------------------------------------------------------------------------------
Other Property and Investments                                                        1,389                      979
---------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:

Deferred charges related to income taxes                                             21,557                   22,697
Prepaid pension costs                                                                 2,488                        -
Debt expense, being amortized                                                         4,355                    4,409
Premium on reacquired debt, being amortized                                           8,154                    9,304
Workforce reduction plan                                                                  -                   12,748
Other                                                                                13,129                   11,009
---------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                              49,683                   60,167
---------------------------------------------------------------------------------------------------------------------
Total Assets                                                                     $1,251,136               $1,189,605
=====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>


                                                                  II-154

<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                                  1999                     1998
--------------------------------------------------------------------------------------------------------------------
                                                                                             (in thousands)

<S>                                                                             <C>                 <C>
Current Liabilities:
Securities due within one year                                                  $   30,020               $   50,020
Notes payable                                                                       57,500                   13,000
Accounts payable --
  Affiliated                                                                        17,002                    8,788
  Other                                                                             43,105                   47,113
Customer deposits                                                                    3,749                    3,272
Taxes accrued --
  Income taxes                                                                       6,865                    1,124
  Other                                                                             35,534                   31,379
Interest accrued                                                                     6,733                    2,955
Vacation pay accrued                                                                 5,218                    4,717
Other                                                                                7,497                   11,448
--------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                          213,223                  173,816
--------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                       321,802                  292,744
--------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes                                                  139,564                  143,852
Deferred credits related to income taxes                                            34,765                   37,277
Accumulated deferred investment tax credits                                         24,695                   25,913
Employee benefits provisions                                                        34,268                   34,148
Workforce reduction plan                                                            11,272                   13,051
Other                                                                               12,770                   10,764
--------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                       257,334                  265,005
--------------------------------------------------------------------------------------------------------------------
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)                          391,968                  391,231
--------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                      $1,251,136               $1,189,605
====================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>


                                                                  II-155

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                                   1999              1998             1999              1998
-----------------------------------------------------------------------------------------------------------------------------
                                                                        (in thousands)                (percent of total)
Long-Term Debt:
First mortgage bonds --

       Maturity                           Interest Rates
       --------                           --------------
      <S>                                 <C>                 <C>               <C>               <C>                   <C>
       June 1, 2023                       7.45%                $ 35,000          $ 35,000
       March 1, 2004                      6.60%                  35,000            35,000
       December 1, 2025                   6.875%                 30,000            30,000
-----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                      100,000           100,000
-----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
       6.05% due May 1, 2003                                     35,000            35,000
       6.75% due June 30, 2038                                   54,564            55,000
       Adjustable rates (6.61% to 6.78% at 1/1/00)
         due 1999-2002                                           80,000            80,000
-----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable                                   169,564           170,000
-----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
     Pollution control revenue bonds --
       Collateralized:
         5.65% to 5.80% due 2007-2023                            26,785            26,805
         Variable rates (3.90% at 1/1/00)
          due 2020-2025                                          10,600            33,900
     Non-collateralized:
         Variable rates (3.90% to 4.00% at 1/1/00)
          due 2020-2028                                          46,220            13,520
-----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                       83,605            74,225
-----------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net                         (1,347)           (1,461)
-----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
  requirement -- $21.9 million)                                 351,822           342,764
Less amount due within one year                                  30,020            50,020
-----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year            $321,802          $292,744            41.2%             39.0%
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                                                  II-156

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                                   1999              1998             1999              1998
-----------------------------------------------------------------------------------------------------------------------------
                                                                         (in thousands)               (percent of total)
<S>                                                           <C>                <C>                <C>                <C>
Company Obligated Mandatorily
  Redeemable Preferred Securities:
$25 liquidation value --
  7.75%                                                        $ 35,000          $ 35,000
-----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million)          35,000            35,000              4.5               4.7
-----------------------------------------------------------------------------------------------------------------------------
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
Less amount due within one year                                       -                 -
-----------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year                       31,809            31,809              4.1               4.2
-----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
  Authorized  - 1,130,000 shares
  Outstanding - 1,121,000 shares in 1999 and 1998                37,691            37,691
  Paid-in capital                                               181,502           179,474
  Premium on preferred stock                                        326               326
Retained earnings                                               172,449           173,740
-----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                               391,968           391,231             50.2              52.1
-----------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                           $780,579          $750,784           100.0%            100.0%
=============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-157

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Mississippi Power Company 1999 Annual Report

----------------------------------------------------------------------------------------------------------------------------
                                                                                  Premium on
                                                     Common         Paid-In        Preferred      Retained
                                                      Stock         Capital         Stock         Earnings         Total
----------------------------------------------------------------------------------------------------------------------------
                                                                              (in thousands)

<S>                                                 <C>            <C>               <C>         <C>              <C>
Balance at January 1, 1997                           $37,691        $179,389          $372        $166,282         $383,734
Net income after dividends on preferred stock              -               -             -          54,010           54,010
Cash dividends on common stock                             -               -             -         (49,400)         (49,400)
Other                                                      -               -           (45)           (475)            (520)
----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997                          37,691         179,389           327         170,417          387,824
Net income after dividends on preferred stock              -               -             -          55,105           55,105
Capital contributions from parent company                  -              85             -               -               85
Cash dividends on common stock                             -               -             -         (51,700)         (51,700)
Other                                                      -               -            (1)            (82)             (83)
----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                          37,691         179,474           326         173,740          391,231
Net income after dividends on preferred stock              -               -             -          54,809           54,809
Capital contributions from parent company                  -           2,028             -               -            2,028
Cash dividends on common stock                             -               -             -         (56,100)         (56,100)
----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                         $37,691        $181,502          $326        $172,449         $391,968
============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-158


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 1999 Annual Report


1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

Mississippi Power Company is a wholly owned subsidiary of Southern Company,
which is the parent company of five integrated Southeast utilities, Southern
Company Services (SCS), Southern Communications Services (Southern LINC),
Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company
(Southern Nuclear), Southern Energy Solutions, and other direct and indirect
subsidiaries. The integrated Southeast utilities -- Alabama Power Company,
Georgia Power Company, Gulf Power Company, Mississippi Power Company, and
Savannah Electric and Power Company -- provide electric service in four
southeastern states. Contracts among the integrated Southeast utilitis 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 the subsidiary companies. Southern LINC provides digital wireless
communications services to the integrated Southeast utilities and also markets
these services to the public within the Southeast. Southern Company Energy
Solutions develops new business opportunities related to energy products and
services. Southern Nuclear provides services to Southern Company's nuclear power
plants. Southern Energy acquires, develops, builds, owns, and operates power
production and delivery facilities and provides a broad range of energy-related
servies to utilities and industrial companies in selected countries around the
world. Southern Energy businesses include independent power projects, integrated
utilities, a distribution company, and energy trading and marketing businesses
outside the southeastern United States.

    Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. Mississippi Power is also
subject to regulation by the FERC and the Mississippi Public Service Commission
(MPSC). The Company follows generally accepted accounting principles and
complies with the accounting policies and practices prescribed by the respective
commissions. The preparation of financial statements in conformity with
generally accepted accounting principles requires the use of estimates and the
actual results may differ from those estimates.

    Prior years' data presented in the financial statements have been
reclassified to conform with the current year presentation.

Related-Party Transactions

The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $45.5 million, $43.9
million, and $34.5 million during 1999, 1998, and 1997, respectively.

Regulatory Assets and Liabilities

Mississippi Power 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:

                                             1999         1998
                                       -------------------------
                                          (in thousands)
Deferred income tax charges              $ 21,557     $ 22,697
Vacation pay                                5,218        4,717
Workforce reduction plan of
  1997                                          -       12,748
Premium on reacquired debt                  8,154        9,304
Deferred environmental costs                  323        1,500
Property damage reserve                    (3,082)        (910)
Deferred income tax credits               (34,765)     (37,277)
Other, net                                   (672)      (2,538)
----------------------------------------------------------------
Total                                    $ (3,267)    $ 10,241
================================================================

    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 the net regulatory assets and liabilities related to that portion of



                                       II-159

<PAGE>

NOTES (continued)
Mississippi Power Company 1999 Annual Report


operations that are not specifically recoverable through regulated rates. In
addition, the Company would be required to determine any impairment to other
assets, including plant, and write down the assets, if impaired, to their fair
value.

Revenues and 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.

    Mississippi Power accrues revenues for service rendered but unbilled at the
end of each fiscal period. The Company's retail and wholesale rates include
provisions to adjust billings for fluctuations in fuel costs, the energy
component of purchased power costs and certain other costs. Retail rates also
include provisions to adjust billings for fluctuations in costs for ad valorem
taxes and certain qualifying environmental costs. Revenues are adjusted for
differences between actual allowable amounts and the amounts included in rates.

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

Depreciation

Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates which approximated 3.3 percent in 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 facilities.

Income Taxes

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

Property, Plant and Equipment

Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction, if
applicable. The cost of maintenance, repairs, and replacement of minor items of
property is charged to maintenance expense except for the maintenance of coal
cars and a portion of the railway track maintenance, which are charged to fuel
stock. The cost of replacements of property (exclusive of minor items of
property) is capitalized.

Cash and Cash Equivalents

For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.

Financial Instruments

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

                                       Carrying          Fair
                                         Amount         Value
                                   ---------------------------
                                          (in millions)
Long-term debt
 At December 31, 1999                      $353          $334
 At December 31, 1998                      $343          $348
Capital trust preferred
  securities:
 At December 31, 1999                       $35           $30
 At December 31, 1998                        35            36
--------------------------------------------------------------

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


                                       II-160




<PAGE>
NOTES (continued)
Mississippi Power Company 1999 Annual Report


Materials and Supplies

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

Provision for Property Damage

Mississippi Power 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.
Effective November 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 1999, the Company provided for such costs by charges to
income of $4.4 million, which is an increase of $2.9 million when compared to
the $1.5 million allowed in both 1998 and 1997. As of December 31, 1999, the
accumulated provision amounted to $3.1 million.

2.  RETIREMENT BENEFITS

Mississippi Power 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 the extent required by the MPSC. 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
                                     ----------------------------
                                             1999           1998
-----------------------------------------------------------------
                                           (in thousands)
Balance at beginning of year             $142,807       $132,131
Service cost                                4,415          3,848
Interest cost                               9,377          9,613
Benefits paid                              (8,050)        (7,845)
Actuarial (gain) loss and
   employee transfers                      (8,619)         5,060
-----------------------------------------------------------------
Balance at end of year                   $139,930       $142,807
=================================================================

                                                Plan Assets
                                     ----------------------------
                                              1999          1998
-----------------------------------------------------------------
                                           (in thousands)
Balance at beginning of year              $198,100      $207,457
Actual return on plan assets                33,216         1,252
Benefits paid                               (8,050)       (7,845)
Employee transfers                          (1,779)       (2,764)
-----------------------------------------------------------------
Balance at end of year                    $221,487      $198,100
=================================================================

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

                                                1999           1998
--------------------------------------------------------------------
                                                (in thousands)
Funded status                               $ 81,557       $ 55,293
Unrecognized transition obligation            (3,814)        (4,359)
Unrecognized prior service cost                4,991          5,405
Unrecognized net gain                        (80,246)       (56,590)
--------------------------------------------------------------------
Prepaid asset (liability) recognized
   in the Balance Sheets                      $2,488       $   (251)
====================================================================

                                       II-161

<PAGE>
NOTES (continued)
Mississippi Power Company 1999 Annual Report


    Components of the plans' net periodic cost were as follows:

                                       1999      1998         1997
------------------------------------------------------------------
                                          (in thousands)
Service cost                        $ 4,415   $ 3,848     $  4,015
Interest cost                         9,377     9,613        9,407
Expected return on
  plan assets                       (14,681)   (13,817)    (12,805)
Recognized net gain                  (1,721)    (1,956)     (1,729)
Net amortization                       (131)      (131)       (119)
------------------------------------------------------------------
Net pension income                  $(2,741)  $ (2,443)   $ (1,231)
==================================================================

Postretirement Benefits

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

                                             Accumulated
                                         Benefit Obligations
                                     ----------------------------
                                             1999           1998
-----------------------------------------------------------------
                                           (in thousands)
Balance at beginning of year              $47,260        $43,417
Service cost                                  982            806
Interest cost                               3,105          3,162
Benefits paid                              (2,256)        (2,302)
Actuarial loss and
   employee transfers                      (3,701)         2,177
-----------------------------------------------------------------
Balance at end of year                    $45,390        $47,260
=================================================================


                                                Plan Assets
                                     ----------------------------
                                             1999           1998
-----------------------------------------------------------------
                                           (in thousands)
Balance at beginning of year              $12,779        $12,189
Actual return on plan assets                1,818            176
Employer contributions                      2,657          2,716
Benefits paid                              (2,256)        (2,302)
-----------------------------------------------------------------
Balance at end of year                    $14,998        $12,779
=================================================================

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

                                                   1999        1998
--------------------------------------------------------------------
                                                (in thousands)
Funded status                                  $(30,392)    $(34,481)
Unrecognized transition obligation                4,621        4,967
Unrecognized net loss (gain)                     (3,406)       1,010
Fourth quarter contributions                        931          577
--------------------------------------------------------------------
Accrued liability recognized in the
    Balance Sheets                             $(28,246)    $(27,927)
====================================================================

    Components of the plans' net periodic cost were as follows:

                                      1999        1998       1997
------------------------------------------------------------------
                                          (in thousands)
Service cost                        $  981      $  806     $  867
Interest cost                        3,105       3,162      2,922
Expected return on
    plan assets                     (1,100)      (989)       (815)
Recognized net (gain) loss               -          -          (7)
Net amortization                       346         346        362
------------------------------------------------------------------
Net postretirement cost             $3,332      $3,325     $3,329
==================================================================

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

                                               1999       1998
 ---------------------------------------------------------------
 Discount                                      7.50%      6.75%
 Annual salary increase                        5.00       4.25
 Long-term return on plan assets               8.50       8.50
 ---------------------------------------------------------------

                                       II-162

<PAGE>

NOTES (continued)
Mississippi Power Company 1999 Annual Report


    An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 percent through the year 2005 and
remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would increase the accumulated
benefit obligation and the service and interest cost components at December 31,
1999 as follows:

                                      1 Percent      1 Percent
                                       Increase      Decrease
-----------------------------------------------------------------
                                           (in thousands)
Benefit obligation                       $2,983       $(2,551)
Service and interest costs                  258          (219)
-----------------------------------------------------------------

Workforce Reduction Programs

    In 1997, approximately one hundred employees of Mississippi Power accepted
the terms of a workforce reduction plan. The total cost to be incurred in
connection with this voluntary plan was expected to be $18.2 million, including
a $2.5 million pension and postretirement benefits curtailment loss. The MPSC
approved the deferral and amortization of these program costs over a period not
to exceed 60 months beginning no later than July 1998. At December 31, 1999, the
Company has completely amortized the $18.2 million.

3. LITIGATION AND REGULATORY MATTERS

Environmental Litigation

On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action in the U.S. District Court against Alabama Power Company, Georgia Power
Company and the system service company. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in Alabama
and Georgia. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The EPA concurrently issued to the integrated
Southeast utilities a notice of violation related to 10 generating facilities,
which includes the five facilities mentioned previously, and the Company's
plants Watson and Greene County. In early 2000, the EPA filed a motion to amend
its complaint to add the violations alleged in its notice of violation, and to
add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The
complaint and notice of violation are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly the Company's
financial condition unless such costs can be recovered through regulated rates.

Retail Rate Adjustment Plans

Mississippi Power'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 Mississippi Power to keep customer prices low. PEP
includes a mechanism for sharing rate adjustments based on the Company's ability
to maintain low rates for customers and on the Company's performance as measured
by three indicators that emphasize price and service to the customer. PEP
provides for semiannual evaluations of Mississippi Power's performance-based
return on investment. Any change in rates is limited to 2 percent of retail
revenues per evaluation period. PEP will remain in effect until the MPSC
modifies or terminates the plan. In September 1996, the MPSC, under PEP,
approved a retail revenue increase of $4.5 million (1.06 percent of annual
retail revenue) which became effective in October 1996. There were no PEP retail
revenue changes for 1999, 1998 or 1997.

Environmental Compliance Overview Plan

The MPSC approved Mississippi Power's Environmental Compliance Overview Plan
(ECO) in 1992. The 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



                                       II-163

<PAGE>

NOTES (continued)
Mississippi Power Company 1999 Annual Report


the MPSC. Under the ECO Plan any increase in the annual revenue requirement is
limited to 2 percent of retail revenues. However, the plan also provides for
carryover of any amount over the 2 percent limit into the next year's revenue
requirement. In 1997, the Company's filing with the MPSC under the ECO Plan
resulted in an annual retail rate increase of $0.9 million. In 1998 and 1999,
the Company's ECO filing resulted in a small decrease in customer prices in each
year. The Company filed its 2000 ECO Plan in January, and if approved as filed,
will result in a small decrease in customer prices.

    Mississippi Power 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. A currently owned site
where manufactured gas plant operations were located prior to the Company's
ownership has been investigated and substantially remediated. The remedial plan
was approved by the Mississippi Department of Environmental Quality. Remediation
of this site began in 1999 and is scheduled to be completed in early 2000. The
Company expects the total remediation costs to be approximately $2.0 million,
with approximately $1.5 million recovered from other parties and the balance
through the ECO Plan. The Company recovers such costs under the ECO Plan as they
are incurred, as provided for in the Company's 1995 ECO Order. As of December
31, 1999, the balance in the liability and regulatory asset accounts was $0.3
million.

Approval for New Capacity

In January 1998, the Company was granted a Certificate of Public Convenience
and Necessity by the MPSC to build approximately 1,000 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, which will lease the facility to the Company (see Note 5, Financing
and Commitments). The Company also requested approval from the MPSC to exclude
the costs of the new facility from retail rate base and to assign the Company's
existing generating capacity to its retail business, beginning in 2001. In
January 1999, the Company and Mississippi Public Utility Staff entered a
stipulation covering the details of cost allocation and ratemaking to effect
this change. In February 1999, the Commission held hearings on this matter and
subsequently granted the Company's request, as modified by the stipulation.

4.  CONSTRUCTION PROGRAM

Mississippi Power is engaged in continuous construction programs, the costs of
which are currently estimated to total $84 million in 2000, $54 million in 2001,
and $61 million in 2002. 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.

5.  FINANCING AND COMMITMENTS

Financing

Mississippi Power's construction program is expected to be financed from
internal and other sources, such as the issuance of additional long-term debt
and preferred securities and the receipt of capital contributions from Southern
Company.

    The amounts of long-term debt and preferred securities that can be issued in
the future will be contingent on market conditions, the maintenance of adequate
earnings levels, regulatory authorizations, and other factors.

    In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the
Company to design and construct, as agent for Escatawpa, a 1,064 megawatt
natural gas combined cycle facility. It is anticipated that the total project
will cost approximately $406 million, and upon project completion in mid 2001,
the Company intends to lease the facility for an initial term of approximately
10 years. It is anticipated that the annual lease payments will approximate $32
million during the initial term.

                                       II-164


<PAGE>
NOTES (continued)
Mississippi Power Company 1999 Annual Report

Bank Credit Arrangements

At December 31, 1999, Mississippi Power had total committed credit agreements
with banks for $104.3 million. At year-end 1999, the unused portion of these
committed credit agreements was $104.3 million. These credit agreements expire
at various dates in 2000. 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. At December 31, 1999, the Company had
$57.5 million of short-term borrowings outstanding.

Assets Subject to Lien

Mississippi Power's mortgage indenture dated as of September 1, 1941, as amended
and supplemented, which secures the first mortgage bonds issued by the Company,
constitutes a direct first lien on substantially all of the Company's fixed
property and franchises.

Lease Agreements

In 1984, Mississippi Power and Gulf States Utilities (now Entergy Corp.) entered
into a forty-year transmission facilities agreement whereby Entergy began paying
a use fee to the Company covering all expenses relative to ownership and
operation and maintenance of a 500 kV line, including amortization of its
original $57 million cost. For the three years ended 1999 use fees collected
under this agreement, net of related expenses, amounted to approximately $3
million each year, and are included within Other Income in the Statements of
Income.

    In 1989, Mississippi Power entered into a twenty-two year lease agreement
for the use of 495 aluminum railcars. In 1994, a second lease agreement for the
use of 250 additional aluminum railcars was also entered into for twenty-two
years. The Company has the option to purchase the 745 railcars at the greater
of lease termination value or fair market value, or to renew the leases at the
end of the lease term. In 1997, a third lease agreement for the use of 360
railcars was also entered into for three years, with a monthly renewal option
for up to an additional nine months. All of these leases, totaling 1,105
railcars, were for the transport of coal at Plant Daniel.

    Gulf Power, as joint owner of Plant Daniel, is responsible for one half of
the lease cost. The Company's share (50%) of the leases, charged to fuel
stock, was $2.8 million in 1999, $2.8 million in 1998, and $2.0 million in
1997. The Company's annual lease payments for 2000 through 2004 will average
approximately $1.8 million and after 2004, lease payments total in aggregate
approximately $14.4 million.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of its generating plants,
Mississippi Power has entered into various long-term commitments for the
procurement of fuel. In most cases, these contracts contain provisions for price
escalations, minimum production levels, and other financial commitments.

    Total estimated obligations at December 31, 1999, were as follows:

    Year                                       Fuel
-----------                              ----------
                                         (in millions)
    2000                                       $147
    2001                                        121
    2002                                        124
    2003                                        125
    2004                                          9
    2005 - 2026                                 115
---------------------------------------------------
    Total commitments                          $641
---------------------------------------------------

Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.

     In 1996, Mississippi Power entered into agreements to purchase options for
summer peaking power for the years 1997 through 2000. The Company has purchased
options from power marketers for up to 250 megawatts of peaking power in 1997;
300 megawatts in 1998; 250 megawatts in 1999; and 400 megawatts in 2000. For the
years ended 1999, 1998 and 1997 Mississippi Power exercised its options to
purchase 250 megawatts, 300 megawatts and 250 megawatts of peaking capacity,
respectively. In June 1997, the MPSC approved Mississippi Power's request that
it be allowed to earn a return on the capacity portion of this agreement. In
1999, Mississippi Power exercised its option to purchase 400 megawatts of summer
peaking capacity for the year 2000.



                                       II-165

<PAGE>
NOTES (continued)
Mississippi Power Company 1999 Annual Report

6.  JOINT OWNERSHIP AGREEMENTS

Mississippi Power and Alabama Power own as tenants in common Units 1 and 2 at
Plant Greene County located in Alabama; and Mississippi Power and Gulf Power
own as tenants in common Units 1 and 2 at Plant Daniel located in Mississippi.

    At December 31, 1999, Mississippi Power'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%      $61,050        $29,636

 Daniel
  Units 1 and 2     1,000         50%     $225,761       $103,213
 ------------------------------------------------------------------

    Mississippi Power's share of plant operating expenses is included in the
corresponding operating expenses in the Statements of Income.

7.  LONG-TERM POWER SALES AGREEMENTS

Mississippi Power and the other utility affiliates of Southern Company have
long-term contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. Because the
energy is generally sold at cost under these agreements, profitability is
primarily affected by revenues from capacity sales. The Company's capacity
revenues under these agreements were not material during the periods reported.

8.  INCOME TAXES

At December 31, 1999, the tax-related regulatory assets and liabilities were $22
million and $35 million, respectively. These assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.

    Details of the federal and state income tax provisions are shown below:

                                     1999        1998       1997
                                ----------------------------------
                                           (in thousands)
 Total provision for
    income taxes
 Federal --
    Current                       $33,379     $20,500    $27,651
    Deferred  --current year        3,747       7,007      8,171
              --reversal of
                 prior years       (7,720)      2,435     (9,236)
 -----------------------------------------------------------------
                                   29,406      29,942     26,586
 -----------------------------------------------------------------
 State --
    Current                         4,881       2,544      5,537
    Deferred  --current year          738       1,568      1,756
              --reversal of
                 prior years         (908)        610     (2,499)
 -----------------------------------------------------------------
                                    4,711       4,722      4,794
 -----------------------------------------------------------------
 Total                             34,117      34,664     31,380
 =================================================================

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

                                        1999             1998
                                   -----------------------------
                                           (in thousands)
 Deferred tax liabilities:
    Accelerated depreciation        $154,698         $153,768
    Basis differences                  8,967            9,642
    Other                             23,108           26,038
 ---------------------------------------------------------------
 Total                               186,773          189,448
 ---------------------------------------------------------------
 Deferred tax assets:
    Other property
     basis differences                21,003           22,391
    Pension and
     other benefits                    9,608            9,441
    Property insurance                 3,419            1,526
    Unbilled fuel                      4,846            2,080
    Other                             11,071           14,406
 ---------------------------------------------------------------
 Total                                49,947           49,844
 ---------------------------------------------------------------
 Net deferred tax
    liabilities                      136,826          139,604
 Portion included in
    current assets, net                2,738            4,248
 ---------------------------------------------------------------
 Accumulated deferred
    income taxes in the
    Balance Sheets                  $139,564         $143,852
 ===============================================================



                                     II-166

<PAGE>
NOTES (continued)
Mississippi Power Company 1999 Annual Report

    Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $1.2 million in 1999, 1998, and 1997. At December 31, 1999, all
investment tax credits available to reduce federal income taxes payable had been
utilized.

    A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                       1999     1998         1997
                                 ----------------------------------
 Federal statutory rate               35.00%   35.00%       35.00%
 State income tax, net of
    federal deduction                  3.37     3.34         3.51
 Non-deductible book
    depreciation                        .77      .47          .47
 Other                                (1.62)   (1.04)       (3.60)
 ------------------------------------------------------------------
 Effective income tax rate            37.52%   37.77%       35.38%
 ==================================================================

    Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis.

9.    COMPANY OBLIGATED MANDATORILY
      REDEEMABLE PREFERRED SECURITIES

In February 1997, Mississippi Power Capital Trust I (Trust I), of which the
Company owns all the common securities, issued $35 million of 7.75 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust I are $36 million aggregate principal amount of the Company's 7.75 percent
junior subordinated notes due February 15, 2037.

    The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.

    The Trust is a subsidiary of the Company, and accordingly is consolidated in
the Company's financial statements.

10. 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:

                                                1999       1998
                                             -------------------
                                                (in thousands)
 Bond improvement fund requirement            $1,000     $1,000
 Less: Portion to be satisfied by
         certifying property additions         1,000      1,000
 ---------------------------------------------------------------
 Cash sinking fund requirement                     -          -
 Redemptions of first mortgage bonds               -          -
 Current portion of other long-term debt      30,000     50,000
 Pollution control bond cash
    sinking fund requirements                     20         20
 ---------------------------------------------------------------
 Total                                       $30,020    $50,020
 ===============================================================

    The first mortgage bond improvement fund requirement is one percent of each
outstanding series authenticated under the indenture of Mississippi Power 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.

11. COMMON STOCK DIVIDEND RESTRICTIONS

Mississippi Power's first mortgage bond indenture and the corporate charter
contain various common stock dividend restrictions. At December 31, 1999,
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-167
<PAGE>
NOTES (continued)
Mississippi Power Company 1999 Annual Report

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data for 1999 and 1998 are as follows:

                                                         Net Income
                                                    After Dividends
                         Operating     Operating       On Preferred
Quarter Ended             Revenues        Income              Stock
--------------------------------------------------------------------
                                     (in thousands)
March 1999                $122,435       $18,122             $7,193
June 1999                  158,590        31,289             14,953
September 1999             201,594        51,609             27,313
December 1999              150,385        18,736              5,350

March 1998                $122,156       $20,299             $8,388
June 1998                  156,612        30,126             13,713
September 1998             191,699        50,948             28,309
December 1998              124,664        13,498              4,696
--------------------------------------------------------------------

    Mississippi Power's business is influenced by seasonal weather conditions
and the timing of rate changes.





                                       II-168
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Mississippi Power Company 1999 Annual Report

---------------------------------------------------------------------------------------------------------------------------------
                                                            1999            1998            1997            1996            1995
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>             <C>             <C>             <C>             <C>
Operating Revenues (in thousands)*                      $633,004        $595,131        $543,588        $544,029        $516,553
Net Income after Dividends
  on Preferred Stock (in thousands)                      $54,809         $55,105         $54,010         $52,723         $52,531
Cash Dividends
  on Common Stock (in thousands)                         $56,100         $51,700         $49,400         $43,900         $39,400
Return on Average Common Equity (percent)                  14.00           14.15           14.00           13.90           14.26
Total Assets (in thousands)                           $1,251,136      $1,189,605      $1,166,829      $1,142,327      $1,148,953
Gross Property Additions (in thousands)                  $75,888         $68,231         $55,375         $61,314         $67,570
---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                     $391,968        $391,231        $387,824        $383,734        $374,884
Preferred stock                                           31,809          31,809          31,896          74,414          74,414
Company obligated mandatorily
  redeemable preferred securities                         35,000          35,000          35,000               -               -
Long-term debt                                           321,802         292,744         291,665         326,379         288,820
---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)           $780,579        $750,784        $746,385        $784,527        $738,118
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                         50.2            52.1            52.0            48.9            50.8
Preferred stock                                              4.1             4.2             4.3             9.5            10.1
Company obligated mandatorily
  redeemable preferred securities                            4.5             4.7             4.7               -               -
Long-term debt                                              41.2            39.0            39.0            41.6            39.1
---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)              100.0           100.0           100.0           100.0           100.0
=================================================================================================================================
Security Ratings:
First Mortgage Bonds -
     Moody's                                                 Aa3             Aa3             Aa3             Aa3             Aa3
     Standard and Poor's                                     AA-             AA-             AA-              A+              A+
     Duff & Phelps                                           AA-             AA-             AA-             AA-             AA-
Preferred Stock -
     Moody's                                                  a1              a1              a1              a1              a1
     Standard and Poor's                                      A-               A               A               A               A
     Duff & Phelps                                            A+              A+              A+              A+              A+
=================================================================================================================================
Customers (year-end):
Residential                                              157,592         156,530         156,650         154,630         154,014
Commercial                                                31,837          31,319          31,667          30,366          29,903
Industrial                                                   546             587             642             639             642
Other                                                        202             200             200             200             194
---------------------------------------------------------------------------------------------------------------------------------
Total                                                    190,177         188,636         189,159         185,835         184,753
=================================================================================================================================
Employees (year-end):                                      1,328           1,230           1,245           1,363           1,421
---------------------------------------------------------------------------------------------------------------------------------
* 1999 data includes the true-up of the unbilled revenue estimates.
</TABLE>






                                                                  II-169
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Mississippi Power Company 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------------------
                                                           1999            1998            1997            1996            1995
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>              <C>            <C>             <C>             <C>
Operating Revenues (in thousands)*:
Residential                                           $ 159,945        $157,642       $ 138,608       $ 137,055       $ 134,286
Commercial                                              153,936         145,677         134,208         131,734         131,034
Industrial                                              151,244         135,039         140,233         141,324         140,947
Other                                                     4,309           4,209           4,193           4,013           3,914
--------------------------------------------------------------------------------------------------------------------------------
Total retail                                            469,434         442,567         417,242         414,126         410,181
Sales for resale  - non-affiliates                      131,004         121,225         105,141          99,596          91,820
Sales for resale  - affiliates                           19,446          18,285          10,143          21,830           7,691
--------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity                619,884         582,077         532,526         535,552         509,692
Other revenues                                           13,120          13,054          11,062           8,477           6,861
--------------------------------------------------------------------------------------------------------------------------------
Total                                                  $633,004        $595,131        $543,588        $544,029        $516,553
================================================================================================================================
Kilowatt-Hour Sales (in thousands)*:
Residential                                           2,248,255       2,248,915       2,039,042       2,079,611       2,040,608
Commercial                                            2,847,342       2,623,276       2,407,520       2,315,860       2,242,163
Industrial                                            4,407,445       3,729,166       3,981,875       3,960,243       3,813,456
Other                                                    40,091          39,772          40,508          39,297          38,559
--------------------------------------------------------------------------------------------------------------------------------
Total retail                                          9,543,133       8,641,129       8,468,945       8,395,011       8,134,786
Sales for resale  - non-affiliates                    3,256,175       3,157,837       2,895,182       2,726,993       2,493,519
Sales for resale  - affiliates                          539,939         552,142         478,884         693,510         243,554
--------------------------------------------------------------------------------------------------------------------------------
Total                                                13,339,247      12,351,108      11,843,011      11,815,514      10,871,859
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents)*:
Residential                                                7.11            7.01            6.80            6.59            6.58
Commercial                                                 5.41            5.55            5.57            5.69            5.84
Industrial                                                 3.43            3.62            3.52            3.57            3.70
Total retail                                               4.92            5.12            4.93            4.93            5.04
Sales for resale                                           3.96            3.76            3.42            3.55            3.84
Total sales                                                4.65            4.71            4.50            4.53            4.69
Residential Average Annual
  Kilowatt-Hour Use Per Customer *                       14,301          14,376          13,132          13,469          13,307
Residential Average Annual
  Revenue Per Customer *                              $1,017.42       $1,007.68         $892.68         $887.66         $875.69
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                          2,086           2,086           2,086           2,086           2,086
Maximum Peak-Hour Demand (megawatts):
Winter                                                    2,125           1,740           1,922           2,030           1,637
Summer                                                    2,439           2,339           2,209           2,117           2,095
Annual Load Factor (percent)                               59.6            58.0            59.1            60.7            60.0
Plant Availability Fossil-Steam (percent):                 91.0            90.0            92.4            91.8            92.1
--------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                       69.4            66.5            70.5            70.4            58.0
Oil and gas                                                15.9            14.5            12.5            12.0            15.2
Purchased power -
  From non-affiliates                                       6.2             8.0             3.0             6.5             2.4
  From affiliates                                           8.5            11.0            14.0            11.1            24.4
--------------------------------------------------------------------------------------------------------------------------------
Total                                                     100.0           100.0           100.0           100.0           100.0
================================================================================================================================
* 1999 data includes the true-up of the unbilled revenue estimates.
</TABLE>





                                                                  II-170



<PAGE>


                      SAVANNAH ELECTRIC AND POWER COMPANY

                               FINANCIAL SECTION


                                     II-171


<PAGE>
MANAGEMENT'S REPORT
Savannah Electric and Power Company 1999 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 generally
accepted accounting principles appropriate in the circumstances and necessarily
include amounts that are based on the best estimates and judgments of
management. Financial information throughout this annual report is consistent
with the financial statements.

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

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

     The audit committee of the board of directors, composed of five 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 generally accepted
accounting principles.



/s/G. Edison Holland, Jr
G. Edison Holland, Jr.
President
and Chief Executive Officer


/s/K. R. Willis
K. R. Willis
Vice President,
Treasurer, Chief Financial Officer
and Assistant Secretary


February 16, 2000



                                       II-172

<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, 1999 and 1998, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 1999. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

   In our opinion, the financial statements (pages II-181 through II-194)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 1999 and
1998, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States.


/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000






                                       II-173

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Savannah Electric and Power Company 1999 Annual Report


RESULTS OF OPERATIONS

Earnings

Savannah Electric and Power Company's net income after dividends on preferred
stock for 1999 totaled $23.1 million, representing a decrease of $0.6 million or
2.4 percent from the prior year. Earnings were down primarily due to lower
non-operating revenues.

     In 1998, earnings were $23.6 million, representing a $0.2 million, or 0.9
percent decrease from the prior year. This was principally the result of a
decrease in other income, net.

Revenues

Total revenues for 1999 were $251.6 million, reflecting a 1.1 percent decrease
when compared to 1998. The following table summarizes the factors affecting
operating revenues for the past three years:

                                          Increase (Decrease)
                                            From Prior Year
                               --------------------------------------
                                    1999        1998         1997
                               --------------------------------------
     Retail --                             (in thousands)
       Growth and price
         changes                 $ 5,633    $   (479)    $  7,664
       Weather                    (5,257)      8,336       (6,186)
       Fuel cost recovery
         and other                  (438)     15,012      (10,002)
    -----------------------------------------------------------------
    Total retail                     (62)     22,869       (8,524)
    -----------------------------------------------------------------
    Sales for resale--
       Non-affiliates             (1,153)      1,081        1,469
       Affiliates                  1,135         964       (1,078)
    -----------------------------------------------------------------
    Total sales for resale           (18)      2,045          391
    -----------------------------------------------------------------
    Other operating revenues      (2,781)      3,264          336
    -----------------------------------------------------------------
    Total operating revenues     $(2,861)   $ 28,178     $ (7,797)
    =================================================================
    Percent change                  (1.1)%      12.5%        (3.3)%
    -----------------------------------------------------------------

    Retail revenues were relatively unchanged in 1999 when compared to 1998.
Reduced demand for energy in the industrial sector and a base rate decrease to
the small business customers partially offset by increased demand in the
residential and commercial sectors contributed to this variance.

     In 1998, retail revenues increased by 10.4 percent over the prior year due
primarily to unusually hot summer weather that resulted in increased energy
sales to residential and commercial customers. A base rate decrease to the small
business customer class, ordered by the Georgia Public Service Commission
(GPSC), was effective in July 1998. See Note 3 to the financial statements for
additional information.

    Under the Company's fuel cost recovery provisions, fuel revenues--including
the fuel component of purchased energy--generally equal fuel expense and have no
effect on earnings.

     Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. Revenues from these sales
were not material during the three-year period.

     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 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 1999 and the percent change by year were as
follows:

                            KWH                Percent Change
                        ------------    -----------------------------
                           1999           1999      1998      1997
                        ------------    -----------------------------
                          (in millions)

Residential                   1,579        2.6%      7.8%     (1.9)%
Commercial                    1,288        4.2       6.9       1.3
Industrial                      713      (20.7)      2.1       5.1
Other                           133        1.1       5.3      (1.4)
                        ------------
Total retail                  3,713       (2.5)      6.0       0.8
Sales for resale--
  Non-affiliates                 51       (3.3)    (43.5)      2.9
  Affiliates                     77       31.8       7.2      30.4
                        ------------
Total                         3,841       (2.0)%     4.8 %     1.2 %
=====================================================================

   Total retail energy sales in 1999 were down by 2.5% from the prior year
reflecting reduced energy sales of 20.7% to industrial customers due to the
shut-down of one industrial customer's facilities in late 1998 and completed
construction of a steam turbine unit by another industrial customer. These
reductions were partially mitigated by increased energy sales of 2.6% and 4.2%
to residential and commercial customers, respectively.

   In 1998, total retail energy sales were up 6.0% over the prior year,
reflecting the impact of the hotter-than-normal weather on energy sales to


                                       II-174

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report


residential and commercial customers and high demand from an industrial
customer.

Expenses

Total operating expenses for 1999 were $201.5 million, a slight increase of $1.2
million from the prior year due primarily to increases in purchased power from
non- affiliates and depreciation and amortization. Purchased power from
non-affiliates increased due principally to higher demand for energy and
increased costs associated with these power purchases. Maintenance expenses
decreased this year compared to 1998 due to repair costs in 1998 related to a
major turbine dismantle inspection. Depreciation and amortization increased
reflecting additional depreciation charges related to the GPSC's accounting
order. See Note 3 to the financial statements for additional information on the
GPSC's 1998 accounting order.

     In 1998, total operating expenses were $200.3 million reflecting a $27.7
million increase from 1997. Major components of this increase included a $17.5
million increase in fuel, a $7.1 million increase in purchased power from
non-affiliates, and a $5.5 million increase in maintenance expense. These
increases, however, were partially offset by a $6.4 million decrease in
purchased power from affiliates. The increase in fuel expense was primarily
attributed to higher demand for energy. The increase in purchased power from
non-affiliates primarily resulted from increased power marketing activities.
Maintenance expenses were higher primarily due to scheduled turbine dismantle
inspection costs. The decline in purchased power from affiliates was due
primarily to an increase in internal generation reflecting system load growth.

     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:

                                          1999     1998     1997
                                       --------------------------
Total energy supply
   (millions of KWHs)                    4,039    4,182    3,964
Sources of energy supply
   (percent) --
     Coal                                   45       42       34
     Oil                                     2        1        -
     Gas                                    10       12        5
     Purchased Power                        43       45       61
Total average cost of
   energy supply (cents)                  2.44     2.35     2.02
-----------------------------------------------------------------

Effects of Inflation

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

Future Earnings Potential

The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from energy sales growth to a less regulated, more
competitive environment.

     Savannah Electric currently operates as a vertically integrated utility
providing electricity to customers within the traditional service area of
southeastern Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC. Prices for electricity relating to jointly owned
generating facilities, interconnecting transmission lines, and the exchange of
electric power are set by the Federal Energy Regulatory Commission (FERC).



                                       II-175


<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report


     Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. 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.

     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 being driven down by
wholesale transmission access and numerous potential new energy suppliers,
including power marketers and brokers. The Company is positioning the business
to meet the challenge of this major change in the traditional practice of
selling electricity.

     Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Georgia, none have been enacted to date. Enactment would require numerous issues
to be resolved, including significant ones relating to transmission pricing and
recovery of any stranded investments. The inability of the Company to recover
its investments, including the regulatory assets described in Note 1 to the
financial statements, could have a material adverse effect on financial
condition and results of operation. The Company is attempting to minimize or
reduce its cost exposure.

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

     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."

     Rates to retail customers served by the Company are regulated by the GPSC.
As part of the Company's rate settlement in 1992, it was informally agreed that
the Company's earned rate of return on common equity should be 12.95 percent. In
1998, the GPSC issued a four-year accounting order settling its review of the
Company's earnings. See Note 3 to the financial statements for additional
information.

     On December 20, 1999, the FERC issued its final rule on Regional
Transmission Organizations (RTOs). The order encourages utilities owning
transmission systems to form RTOs on a voluntary basis. To facilitate the
development of RTOs, the FERC will convene regional conferences for utilities,
customers, and other members of the public to discuss the formation of RTOs. In
addition to participating in the regional conferences, utilities owning
transmission systems, including the Company, are required to make a filing by
October 15, 2000. The filing must contain either a proposal for RTO
participation or a description of the efforts made to participate in an RTO, the
reasons for non-participation, any obstacles to participation, and any plans for
further work toward participation. The RTOs that are proposed in the filings
should be operational by December 15, 2001. The Company is evaluating this issue
and formulating its response. The outcome of this matter cannot now be
determined.

     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


                                       II-176

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report


statements under "Regulatory Assets and Liabilities" for additional information.

Exposure to Market Risks

Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statement as incurred. At December 31, 1999, exposure from these activities was
not material to the Company's financial statements. Also, based on the Company's
overall interest rate exposure at December 31, 1999, a near-term 100 basis point
change in interest rates would not materially affect the financial statements.

New Accounting Standards

The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 1, 2001. This statement
establishes accounting and reporting standards for derivative instruments --
including certain derivative instruments embedded in other contracts -- and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.

Year 2000 Challenge

The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.

     Original projected total costs for Year 2000 readiness were approximately
$1.2 million. Final projected costs are $1.3 million of which $0.1 million is
projected to be spent in 2000. These costs include labor necessary to identify,
test, and renovate affected devices and systems, and costs for reporting
requirements to state and federal agencies. From its inception through December
31, 1999, the Year 2000 program costs, recognized as expense, amounted to $1.2
million.

FINANCIAL CONDITION

Overview

The principal change in the Company's financial condition in 1999 was the
addition of $29.8 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.

Capital Structure

As of December 31, 1999, the Company's capital structure consisted of 48.3
percent common stockholders' equity, 11.0 percent trust preferred securities,
and 40.7 percent long-term debt, excluding amounts due within one year. The
Company's long-term financial objective for capitalization ratios is to maintain
a capital structure of common stockholders' equity at 48 percent, preferred
securities at 10 percent and debt at 42 percent.

     Maturities and retirements of long-term debt were $16 million in 1999,
$30 million in 1998 and $14 million in 1997. Included in the 1999 maturities and
retirements is the purchase by Savannah Electric of all $15 million outstanding
of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.

     During 1998, the Company issued $30 million of Series A 6 5/8% senior
retail intermediate bonds maturing in 2015. The Company used these proceeds to
redeem the remaining amount of its 8.30% first mortgage bonds due in 2022. Also
in 1998, the Company redeemed all of its 1,400,000 shares of 6.64% Series
Preferred Stock at a redemption price of $25 per share, plus accrued dividends
through the date of redemption. 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.




                                       II-177
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report


     The composite interest rates and dividend rates for the years 1997 through
1999 as of year-end were as follows:

                                     1999       1998       1997
                                  -------------------------------
Composite interest rates
  on long-term debt                   6.4%       6.5%       6.9%
Preferred stock dividend rate           -%         -%       6.6%
Trust preferred securities
   dividend rate                      6.9%       6.9%         -%
-----------------------------------------------------------------

Capital Requirements for Construction

The Company's projected construction expenditures for the next three years total
$91.8 million ($25.6 million in 2000, $30.4 million in 2001, and $35.8 million
in 2002). Actual construction costs may vary from this estimate because of
factors such as changes in: business conditions; environmental regulations; load
projections; the cost and efficiency of construction labor, equipment and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered. Construction 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
$31.8 million will be needed by the end of 2002 for maturities of long-term debt
and present sinking fund requirements.

Environmental Matters

In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act--the acid rain compliance provision of the law--significantly affected
the Company and other subsidiaries of Southern Company. Specific reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
are required in two phases. Phase I compliance began in 1995 and initially
affected 28 generating units of Southern Company. As a result of Southern
Company's compliance strategy, an additional 22 generating units, which included
four of the Company's units, were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.

     Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $2 million for Savannah Electric.

     For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired plants
as necessary to meet Phase II limits and ozone non-attainment requirements.
Compliance for Phase II and initial ozone non-attainment requirements increased
total estimated construction expenditures by approximately $105 million. Phase
II compliance is not expected to have a material impact on Savannah Electric.

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

     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 EPA concurrently issued to the integrated Southeast
utilities a notice of violation related to 10 generating facilities, which
includes the five facilities mentioned previously and the Company's Plant Kraft.
In early 2000, the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation, and to add Gulf Power,
Mississippi Power, and Savannah Electric as defendants. The complaint and
notice of violation are similar to those brought against and issued to
several other electric utilities. These complaints and notices of violation
allege that the utilities had failed to secure necessary permits or install
additional pollution equipment when performing maintenance and construction at
coal burning plants constructed or under construction prior to 1978. Southern
Company believes that its integrated utilities complied with applicable laws
and the EPA's regulations and interpretations in effect at the time the work in
question took place. The Clean Air Act authorizes civil penalties of up to
$27,500 per day per violation at each generating unit. Prior to January 30,
1997, the penalty was $25,000 per


                                       II-178

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report


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 July 1997, the EPA revised the national ambient air quality standards
for ozone and particulate matter. This revision makes the standards
significantly more stringent. In September 1998, the EPA issued the final
regional nitrogen oxide rules to the states for implementation. The final rule
affects 22 states including Georgia. The EPA's July 1997 standards and the
September 1998 rule are being challenged in the courts by several states and
industry groups. Implementation of the final state rules for these three
initiatives could require substantial further reductions in nitrogen oxide and
sulfur dioxide emissions from fossil-fired generating facilities and other
industries in these states. Additional compliance costs and capital expenditures
resulting from the implementation of these rules and standards cannot be
determined until the results of legal challenges are known, and the states have
adopted their final rules.

     The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: additional controls for hazardous
air pollutant emissions; control strategies to reduce regional haze; and
hazardous waste disposal requirements. The impact of 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
currently or previously owned. The Company conducts studies to determine the
extent of any required cleanup costs and will recognize in the financial
statements any 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 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

At December 31, 1999, the Company had $6.6 million of cash and $26.2 million of
unused short-term and revolving credit arrangements with banks to meet its
short-term cash needs and to provide additional interim funding for the
Company's construction program. Revolving credit arrangements total $20 million,
of which $10 million expires December 31, 2001 and $10 million expires December
31, 2002.

     It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulation, will be derived
from sources similar to those used in the past. These sources were primarily
from the issuances of first mortgage bonds, other long-term debt, and preferred
stock, in addition to pollution control revenue bonds issued for the Company's
benefit by public authorities, to meet long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company is required to meet certain
earnings coverage requirements specified in its mortgage indenture and corporate
charter to issue new first mortgage bonds and preferred stock. The Company's
coverage ratios are sufficiently high to permit, at present interest rate
levels, any foreseeable security sales. In 1998, the Company obtained
stockholder approval to amend the corporate charter including the elimination of
the 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-179

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report


Cautionary Statement Regarding Forward-Looking Information

Savannah Electric and Power Company's 1999 Annual Report contains
forward-looking and historical information. The Company cautions that there are
various important factors that could cause actual results to differ materially
from those indicated in the forward-looking information. Accordingly, there can
be no assurance that such indicated results will be realized. These factors
include legislative and regulatory initiatives regarding deregulation and
restructuring of the electric utility industry; the extent and timing of the
entry of additional competition in the Company's markets; potential business
strategies--including acquisitions or dispositions of assets or internal
restructuring--that may be pursued by the Company; state and federal rate
regulation; changes in or application of environmental and other laws and
regulations to which the Company is subject; political, legal and economic
conditions and developments; financial market conditions and the results of
financing efforts; changes in commodity prices and interest rates; weather and
other natural phenomena; and other factors discussed in the reports--including
Form 10-K--filed from time to time by the Company with the Securities and
Exchange Commission.



                                       II-180

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Savannah Electric and Power Company 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------
                                                                      1999                 1998                1997
--------------------------------------------------------------------------------------------------------------------
                                                                                (in thousands)

<S>                                                               <C>                  <C>                 <C>
Operating Revenues (Note 1):
Retail sales                                                      $242,265             $242,327            $219,458
Sales for resale --
  Non-affiliates                                                     3,395                4,548               3,467
  Affiliates                                                         4,151                3,016               2,052
Other revenues                                                       1,783                4,564               1,300
--------------------------------------------------------------------------------------------------------------------
Total operating revenues                                           251,594              254,455             226,277
--------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                              50,530               53,021              35,563
  Purchased power --
   Non-affiliates                                                   14,398                9,460               2,347
   Affiliates                                                       33,398               35,687              42,107
  Other                                                             50,341               49,055              47,735
Maintenance                                                         16,333               18,711              13,236
Depreciation and amortization (Notes 1 and 3)                       23,841               22,032              20,152
Taxes other than income taxes                                       12,690               12,342              11,494
--------------------------------------------------------------------------------------------------------------------
Total operating expenses                                           201,531              200,308             172,634
--------------------------------------------------------------------------------------------------------------------
Operating Income                                                    50,063               54,147              53,643
Other Income (Expense):
Interest income                                                        169                  384                 279
Other, net                                                            (663)              (1,698)               (542)
--------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                           49,569               52,833              53,380
--------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt                                           9,300               10,383              10,907
Interest on notes payable                                              879                  278                 172
Amortization of debt discount, premium and expense, net                948                  853                 739
Other interest charges                                                 811                  341                 205
Distributions on preferred securities of subsidiary                  2,740                  167                   -
--------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                               14,678               12,022              12,023
--------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                        34,891               40,811              41,357
Income taxes (Notes 1 and 6)                                        11,808               15,101              15,186
--------------------------------------------------------------------------------------------------------------------
Net Income                                                          23,083               25,710              26,171
Dividends on Preferred Stock                                             -                2,066               2,324
--------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock                     $ 23,083             $ 23,644            $ 23,847
====================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>


                                                                  II-181

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Savannah Electric and Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------------
                                                                           1999                1998                1997
------------------------------------------------------------------------------------------------------------------------
                                                                                         (in thousands)

<S>                                                                    <C>                 <C>                 <C>
Operating Activities:
Net income                                                             $ 23,083            $ 25,710            $ 26,171
Adjustments to reconcile net income
  to net cash provided from operating activities --
        Depreciation and amortization                                    25,454              23,531              21,083
        Deferred income taxes and investment tax credits, net            (3,353)              7,011               3,841
        Other, net                                                          (47)                (89)             (2,816)
        Changes in certain current assets and liabilities --
          Receivables, net                                               (5,999)             (9,875)             (1,938)
          Fossil fuel stock                                              (2,125)                221                 687
          Materials and supplies                                         (1,906)                484               1,033
          Accounts payable                                                1,133                 470              (1,608)
          Other                                                           1,731              (4,859)              3,366
------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                              37,971              42,604              49,819
------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                                (29,833)            (18,071)            (18,846)
Other                                                                    (1,715)              1,617              (1,418)
------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                  (31,548)            (16,454)            (20,264)
------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                34,300                   -              (5,000)
Proceeds --
    Other long-term debt                                                      -              30,000              13,870
    Preferred securities                                                      -              40,000                   -
    Capital contribution from parent company                              1,099                   -                   -
Retirements --
    First mortgage bonds                                                (15,800)            (30,000)                  -
    Other long-term debt                                                   (481)               (478)            (14,303)
    Preferred stock                                                           -             (35,000)                  -
Payment of preferred stock dividends                                          -              (2,556)             (2,324)
Payment of common stock dividends                                       (25,200)            (23,500)            (20,500)
Other                                                                       250              (4,798)               (368)
------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities                                   (5,832)            (26,332)            (28,625)
------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                     591                (182)                930
Cash and Cash Equivalents at Beginning of Period                          5,962               6,144               5,214
------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                              $ 6,553            $  5,962             $ 6,144
========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
    Interest (net of amount capitalized)                                $14,212             $12,198             $11,619
    Income taxes (net of refunds)                                        12,647               9,666              11,150
------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>



                                                                  II-182

<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Savannah Electric and Power Company 1999 Annual Report

-------------------------------------------------------------------------------------------------------------------
Assets                                                                                1999                    1998
-------------------------------------------------------------------------------------------------------------------
                                                                                             (in thousands)

<S>                                                                                <C>                     <C>
Current Assets:
Cash and cash equivalents                                                          $ 6,553                 $ 5,962
Receivables --
  Customer accounts receivable                                                      20,752                  18,030
  Unrecovered retail fuel clause revenue                                            21,089                  17,628
  Other accounts and notes receivable                                                3,505                   3,543
  Affiliated companies                                                               1,195                   1,388
  Accumulated provision for uncollectible accounts                                    (237)                   (284)
Fossil fuel stock, at average cost                                                   7,109                   4,984
Materials and supplies, at average cost (Note 1)                                     8,402                   6,496
Other                                                                                2,869                   4,772
-------------------------------------------------------------------------------------------------------------------
Total current assets                                                                71,237                  62,519
-------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment:
In service (Notes 1 and 8)                                                         804,096                 781,964
Less accumulated provision for depreciation                                        360,639                 341,930
-------------------------------------------------------------------------------------------------------------------
                                                                                   443,457                 440,034
Construction work in progress                                                        6,561                   2,908
-------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment                                                450,018                 442,942
-------------------------------------------------------------------------------------------------------------------
Other Property and Investments                                                       1,506                   1,420
-------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 6)                                   16,063                  17,130
Cash surrender value of life insurance for deferred compensation plans              16,305                  14,179
Prepaid pension costs (Note 2)                                                       1,201                   3,281
Debt expense, being amortized                                                        3,155                   3,554
Premium on reacquired debt, being amortized                                          8,385                   8,570
Other                                                                                2,348                   2,204
-------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                             47,457                  48,918
-------------------------------------------------------------------------------------------------------------------
Total Assets                                                                      $570,218                $555,799
===================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>


                                                                  II-183
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Savannah Electric and Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                                 1999                    1998
------------------------------------------------------------------------------------------------------------------
                                                                                            (in thousands)

<S>                                                                               <C>                    <C>
Current Liabilities:
Securities due within one year (Note 8)                                            $    704               $    689
Notes payable                                                                        34,300                      -
Accounts payable --
  Affiliated                                                                          4,632                  5,014
  Other                                                                              11,118                 10,833
Customer deposits                                                                     5,426                  5,224
Taxes accrued --
  Income taxes                                                                        3,046                  2,467
  Other                                                                               3,013                  2,891
Interest accrued                                                                      3,237                  3,815
Vacation pay accrued                                                                  2,142                  1,978
Other                                                                                 5,742                  6,700
------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                            73,360                 39,611
------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                        147,147                163,443
------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 6)                                           80,318                 82,778
Deferred credits related to income taxes (Note 6)                                    19,687                 21,349
Accumulated deferred investment tax credits (Note 6)                                 11,280                 11,943
Deferred compensation plans                                                          10,624                  9,788
Employee benefits provisions (Note 2)                                                 7,805                  7,620
Other                                                                                 5,150                  3,402
------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                        134,864                136,880
--------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
  securities of subsidiary trust holding company junior
  subordinated notes (See accompanying statements) (Note 7)                          40,000                 40,000
------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                           174,847                175,865
------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                         $570,218               $555,799
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>


                                                                  II-184

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Savannah Electric and Power Company 1999 Annual Report

------------------------------------------------------------------------------------------------------------------------------------
                                                                              1999              1998           1999            1998
------------------------------------------------------------------------------------------------------------------------------------
                                                                                   (in thousands)              (percent of total)
Long-Term Debt (Note 8):
First mortgage bonds --
       Maturity                           Interest Rates
       --------                           --------------
       <S>                                <C>                              <C>               <C>              <C>             <C>
       July 1, 2003                       6.375%                           $20,000           $20,000
       May 1, 2006                        6.90%                             20,000            20,000
       July 1, 2023                       7.40%                             24,200            25,000
       May 1, 2025                        7.875%                                 -            15,000
------------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                                  64,200            80,000
------------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
       6.88% due June 1, 2001                                               10,000            10,000
       6.625% due March 17, 2015                                            30,000            30,000
       Adjustable rates (6.28% and 6.66% at 1/1/00)
         due 2001                                                           20,000            20,000
------------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable                                               60,000            60,000
------------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
      Pollution control revenue bonds --
         Collateralized:
          Variable rates (4.00% at 1/1/99)
             due 2016                                                            -             4,085
         Non-collateralized:
           Variable rates (3.65% to 3.95% at 1/1/00)
             due 2016-2037                                                  17,955            13,870
------------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                                  17,955            17,955
------------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations                                                5,696             6,177
------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
  requirement -- $9.5 million)                                             147,851           164,132
Less amount due within one year (Note 8)                                       704               689
------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year                  147,147           163,443          40.7%           43.1%
------------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
  Redeemable Preferred Securities (Note 7):
$25 liquidation value --
  6.85%                                                                     40,000            40,000
------------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million)                     40,000            40,000           11.0            10.5
------------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (Note 9):
Common stock, par value $5 per share --
  Authorized  - 16,000,000 shares
  Outstanding - 10,844,635 shares
   Par value                                                                54,223            54,223
Paid-in capital                                                              9,787             8,688
Retained earnings                                                          110,837           112,954
------------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                                          174,847           175,865           48.3            46.4
------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                      $361,994          $379,308         100.0%          100.0%
====================================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-185

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Savannah Electric and Power Company 1999 Annual Report

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

                                                                  Common            Paid-In           Retained
                                                                   Stock            Capital           Earnings            Total
---------------------------------------------------------------------------------------------------------------------------------
                                                                                    (in thousands)

<S>                                                             <C>                 <C>             <C>                <C>
Balance at January 1, 1997                                       $54,223             $8,688          $109,373           $172,284
Net income after dividends on preferred stock                          -                  -            23,847             23,847
Cash dividends                                                         -                  -           (20,500)           (20,500)
---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997                                      54,223              8,688           112,720            175,631
Net income after dividends on preferred stock                          -                  -            23,644             23,644
Cash dividends                                                         -                  -           (23,500)           (23,500)
Other                                                                  -                  -                90                 90
---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                                      54,223              8,688           112,954            175,865
Net income after dividends on preferred stock                          -                  -            23,083             23,083
Capital contributions from parent company                              -              1,099                 -              1,099
Cash dividends                                                         -                  -           (25,200)           (25,200)
---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 (Note 9)                            $54,223             $9,787          $110,837           $174,847
=================================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                  II-186


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 1999 Annual Report


1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

Savannah Electric and Power Company (the Company), is a wholly owned subsidiary
of Southern Company, which is the parent company of five integrated Southeast
utilities, Southern Company Services, Inc. (SCS), Southern Communications
Services (Southern LINC), Southern Company Energy Solutions, Southern Energy,
Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear),
and other direct and indirect subsidiaries. The integrated Southeast utilities
provide electric service in four states. Contracts among the integrated
Southeast utilities--related to jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power--are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. SCS, a system service company provides, at
cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Company Energy Solutions develops new business opportunities related to
energy products and services. Southern Nuclear provides services to Southern
Company's nuclear power plants. Southern Energy acquires, develops, builds, owns
and operates power production and delivery facilities and provides a broad range
of energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States.

     Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
also is subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows generally accepted accounting principles
and complies with the accounting policies and practices prescribed by the GPSC.
The preparation of financial statements in conformity with generally accepted
accounting principles requires the use of estimates, and the actual results may
differ from those estimates.

     Certain prior years' data presented in the financial statements has been
reclassified to conform with the current year presentation.

Related-Party Transactions

The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $16.0 million, $15.3
million, and $13.3 million during 1999, 1998, and 1997, respectively.

Regulatory Assets and Liabilities

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

                                            1999          1998
                                     --------------------------
                                           (in thousands)
Deferred income tax charges             $ 16,063      $ 17,130
Premium on reacquired debt                 8,385         8,570
Deferred income tax credits              (19,687)      (21,349)
Storm damage reserves                     (1,392)       (1,580)
Accelerated depreciation                  (3,000)       (1,000)
---------------------------------------------------------------
Total                                   $    369      $  1,771
===============================================================

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



                                       II-187

<PAGE>
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report


Revenues and Fuel Costs

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area of
southeastern Georgia, and to wholesale customers in the Southeast.

    Revenues are accrued for service rendered but unbilled 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 1999, the GPSC approved increases of slightly over three-tenths of a cent
per kilowatt-hour in the Company's fuel allowance.

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 1999, and
2.9 percent in 1998 and 1997. When property subject to depreciation is retired
or otherwise disposed of in the normal course of business, its cost--together
with the cost of removal, less salvage--is charged to the accumulated provision
for depreciation. Minor items of property included in the original cost of the
plant are retired when the related property unit is retired. Depreciation
expense includes an amount for the expected cost of removal of certain
facilities. See Note 3 to the financial statements for more information.

Income Taxes

The Company, which is included in the consolidated federal income tax return
filed by Southern Company, uses the liability method of accounting for deferred
income taxes and provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.

Allowance for Funds Used During Construction
  (AFUDC)

AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rates used by the Company to calculate AFUDC
were 6.26 percent in 1999, 8.00 percent in 1998 and 9.24 percent in 1997.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost less regulatory
disallowances and impairments. Original cost includes: materials; labor; minor
items of property; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the estimated cost of
funds used during construction. The cost of maintenance, repairs, and
replacement of minor items of property is charged to maintenance expense. The
cost of replacements of property (exclusive of minor items of property) is
capitalized.

Cash and Cash Equivalents

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




                                       II-188

<PAGE>
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report


Financial Instruments

The Company's financial instruments for which the carrying amounts did not equal
fair value at December 31 were as follows:

                                      Carrying           Fair
                                        Amount          Value
                                    --------------------------
                                          (in millions)
Long-term debt:
    At December 31, 1999                 $142             $136
    At December 31, 1998                  158              162
Trust preferred securities:
    At December 31, 1999                  $40              $31
    At December 31, 1998                   40               40

     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 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.

2.  RETIREMENT BENEFITS

The Company has defined benefit, trusteed, non-contributory pension plans that
cover substantially all employees. The Company provides certain medical care and
life insurance benefits for retired employees. Substantially all these employees
may become eligible for such benefits when they retire. The Company funds trusts
to the extent required by the GPSC. The measurement date for plan assets and
obligations is September 30 of each year.

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
                                    ---------------------------
                                          1999          1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $59,207       $51,720
Service cost                             1,746         1,495
Interest cost                            3,893         3,806
Benefits paid                           (3,414)       (3,392)
Actuarial (gain) loss and
    employee transfers                  (1,856)        4,343
Amendments                                 385         1,235
---------------------------------------------------------------
Balance at end of year                 $59,961       $59,207
===============================================================

                                           Plan Assets
                                    ---------------------------
                                          1999          1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $49,630       $50,630
Actual return on plan assets             8,168           171
Employer contributions                       -         2,464
Benefits paid                           (3,414)       (3,392)
Employee transfers                          96          (243)
---------------------------------------------------------------
Balance at end of year                 $54,480       $49,630
===============================================================

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

                                              1999         1998
-----------------------------------------------------------------
                                              (in thousands)
Funded status                              $(5,481)     $(9,577)
Unrecognized transition
    obligation                                 178          266
Unrecognized prior service cost              2,996        2,874
Unrecognized net loss                        3,508        9,718
-----------------------------------------------------------------
Prepaid asset recognized in
    the Balance Sheets                     $ 1,201      $ 3,281
=================================================================


                                     II-189

<PAGE>
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report


      Components of the plans' net periodic cost were as follows:

                                   1999       1998       1997
-----------------------------------------------------------------
                                        (in thousands)
Service cost                     $1,746     $1,495     $1,393
Interest cost                     3,893      3,806      3,556
Expected return on plan
    assets                       (4,063)    (3,992)    (3,782)
Recognized net loss                 152          2        475
Net amortization                    352        334        280
-----------------------------------------------------------------
Net pension cost                 $2,080     $1,645     $1,922
=================================================================

Postretirement Benefits

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

                                            Accumulated
                                        Benefit Obligations
                                    ---------------------------
                                          1999          1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $23,556       $20,899
Service cost                               404           348
Interest cost                            1,549         1,528
Benefits paid                             (756)         (839)
Actuarial (gain) loss and
    employee transfers                  (1,849)        1,620
---------------------------------------------------------------
Balance at end of year                 $22,904       $23,556
===============================================================


                                             Plan Assets
                                    ---------------------------
                                         1999          1998
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $3,803        $3,110
Actual return on plan assets              476            85
Employer contributions                  1,731         1,447
Benefits paid                            (756)         (839)
---------------------------------------------------------------
Balance at end of year                 $5,254        $3,803
===============================================================


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

                                          1999           1998
---------------------------------------------------------------
                                           (in thousands)
Funded status                         $(17,650)    $(19,753)
Unrecognized transition
    obligation                           6,419        6,913
Unrecognized net loss                    3,311        5,444
Fourth quarter contributions             1,336        1,152
---------------------------------------------------------------
Accrued liability recognized in
    the Balance Sheets                 $(6,584)    $ (6,244)
===============================================================

    Components of the plans' net periodic cost were as follows:

                                        1999     1998      1997
----------------------------------------------------------------
                                            (in thousands)
Service cost                          $  404   $  348    $  319
Interest cost                          1,549    1,528     1,499
Expected return on plan assets          (345)    (276)     (211)
Recognized net loss                      152      104       125
Net amortization                         494      494       494
----------------------------------------------------------------
Net postretirement cost               $2,254   $2,198    $2,226
================================================================

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

                                          1999         1998
---------------------------------------------------------------
Discount                                  7.50%        6.75%
Annual salary increase                    5.00         4.25
Long-term return on plan assets           8.50         8.50
---------------------------------------------------------------

      An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1999 as follows:

                                       II-190
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report



                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
                                          (in thousands)
Benefit obligation                     $1,316       $(1,244)
Service and interest costs                106          (100)
===============================================================

     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. Benefit costs
associated with this plan were $0.5 million for 1999, and $0.4 million for 1998
and 1997.

Work Force Reduction Program

In 1997, the Company incurred a $1.9 million, one-time charge to other operation
expense for costs related to the implementation of a work force reduction
program.

3.  REGULATORY 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 EPA concurrently issued to the integrated Southeast utilities a
notice of violation related to 10 generating facilities, which includes the five
facilities mentioned previously and the Company's Plant Kraft. In early 2000,
the EPA filed a motion to amend its complaint to add the violations alleged in
its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah
Electric as defendants.   The complaint and notice of violation are similar to
those brought against and issued to several other electric utilities. These
complaints and notices of violation allege that the utilities had failed to
secure necessary permits or install additional pollution equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. Southern Company believes that its integrated
utilities complied with applicable laws and the EPA's regulations and
interpretations in effect at the time the work in question took place. The Clean
Air Act authorizes civil penalties of up to $27,500 per day per violation at
each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

     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 the next 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. The Company
is also precluded from asking for a rate increase except upon significant
changes in economic conditions, new laws, or regulations. There will be a
quarterly monitoring of the Company's earnings performance.

4.  CONSTRUCTION PROGRAM

The Company is engaged in a continuous construction program, currently estimated
to total $25.6 million in 2000, $30.4 million in 2001, and $35.8 million in
2002. 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 transmission and distribution facilities and
the upgrading of generating plants will continue.




                                       II-191

<PAGE>

NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report


5.  FINANCING AND COMMITMENTS

General

To the extent possible, the Company's construction program is expected to be
financed from internal sources and from the issuance of additional long-term
debt and capital contributions from Southern Company.

     The amounts of long-term debt and preferred securities that can be issued
in the future will be contingent on market conditions, the maintenance of
adequate earnings levels, regulatory authorizations, and other factors.

Bank Credit Arrangements

At the end of 1999, unused credit arrangements with six banks totaled $26.2
million and expire at various times during 2000.

     The Company has revolving credit arrangements of $20 million, of which $10
million expires December 31, 2001 and $10 million expires December 31, 2002.
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.

Assets Subject to Lien

As amended and supplemented, the Company's Indenture of Mortgage, which secures
the first mortgage bonds issued by the Company, constitutes a direct first lien
on substantially all of the Company's fixed property and franchises. A second
lien for $10 million of bank debt is secured by a portion of the Plant Kraft
property and a second lien for $34 million in bank notes is secured by a portion
of the Plant McIntosh property.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. The Company has fuel
commitments of $15 million and $9 million for 2000 and 2001, respectively.

     In 1999, the Company entered into a purchased power agreement for 200
megawatts of capacity from Georgia Power Company's combined cycle combustion
turbine units currently under construction at Plant Wansley and due to begin
operation in 2002.

Operating Leases

The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $0.5 million for 1999, $1.1 million for 1998 and $1.2
million for 1997.

     At December 31, 1999, estimated future minimum lease payments for
noncancelable operating leases were as follows:

                                         Rental Commitments
                                         --------------------
                                           (in thousands)
2000                                         $  483
2001                                            483
2002                                            483
2003                                            483
2004                                            483
2005 and thereafter                          $6,485
-------------------------------------------------------------

6.  INCOME TAXES

At December 31, 1999, tax-related regulatory assets and liabilities were $16.1
million and $19.7 million, respectively. The assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. The liabilities are attributable to deferred taxes previously
recognized at rates higher than current enacted tax law and to unamortized
investment tax credits.



                                       II-192

<PAGE>
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report


     Details of income tax provisions are as follows:

                                        1999      1998       1997
                                  --------------------------------
                                          (in thousands)
Total provision for income taxes
Federal --
   Currently payable                 $12,968   $ 6,763    $ 9,743
   Deferred  -- current year             354     8,377      4,522
             -- reversal of
                prior years           (3,683)   (2,565)    (1,381)
------------------------------------------------------------------
                                       9,639    12,575     12,884
------------------------------------------------------------------
State --
   Currently payable                   2,193     1,327      1,603
   Deferred  -- current year             (34)    1,174        569
             -- reversal of
                prior years               10        25        130
------------------------------------------------------------------
                                       2,169     2,526      2,302
------------------------------------------------------------------
Total                                $11,808   $15,101    $15,186
==================================================================

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

                                                1999       1998
                                            --------------------
Deferred tax liabilities:                       (in thousands)
   Accelerated depreciation                  $73,400    $75,187
   Property basis differences                  6,917      7,591
   Other                                      12,031     10,187
----------------------------------------------------------------
Total                                         92,348     92,965
----------------------------------------------------------------
Deferred tax assets:
   Pension and other benefits                  6,925      4,892
   Other                                       2,935      2,828
----------------------------------------------------------------
Total                                          9,860      7,720
----------------------------------------------------------------
Net deferred tax liabilities                  82,488     85,245
Portions included in current assets, net      (2,170)    (2,467)
----------------------------------------------------------------
Accumulated deferred income taxes
   in the Balance Sheets                     $80,318    $82,778
================================================================

     Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $0.7 million in 1999, 1998 and 1997. At December 31, 1999, all
investment tax credits available to reduce federal income taxes payable had been
utilized.

     A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                        1999     1998       1997
                                    -----------------------------
 Federal statutory tax rate               35%      35%       35%
 State income tax, net of
    federal income tax benefit             4        4         4
 Other                                    (5)      (2)       (2)
 ----------------------------------------------------------------
 Effective income tax rate                34%      37%       37%
 ================================================================

     Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis.

7.   CUMULATIVE PREFERRED STOCK AND
     TRUST PREFERRED SECURITIES

In November 1998, the Company redeemed all of its 1,400,000 shares of 6.64%
Series Preferred Stock at a redemption price of $25 per share, plus accrued
dividends through the date of redemption.

     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
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.

8.   LONG-TERM DEBT AND LONG-TERM DEBT
     DUE WITHIN ONE YEAR

The Company's Indenture related to its First Mortgage Bonds is unlimited as to
the authorized amount of bonds which may be issued, provided that required
property additions, earnings and other provisions of such Indenture are met.




                                       II-193
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report


     Maturities and retirements of long-term debt were $16 million in 1999,
$30 million in 1998 and $14 million in 1997. Included in the 1999 maturities and
retirements is the purchase by Savannah Electric of all $15 million outstanding
of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.

     In 1998, the Company issued $30 million of Series A 6 5/8% senior retail
intermediate bonds maturing in 2015. The Company used these proceeds to redeem
the remaining amount of its 8.30% first mortgage bonds due in 2022.

     Assets acquired under capital leases are recorded as utility plant in
service, and the related obligation is classified as other long-term debt.
Leases are capitalized at the net present value of the future lease payments.
However, for ratemaking purposes, these obligations are treated as operating
leases, and as such, lease payments are charged to expense as incurred.

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

                                                   1999       1998
                                              ---------------------
                                                  (in thousands)
Bond sinking fund requirement                      $650       $800
Less:
   Portion to be satisfied by
     certifying property additions                  650          -
   Reacquired bonds and/or cash deposits              -        800
-------------------------------------------------------------------
Cash sinking fund requirement                         -          -
Other long-term debt maturities                     704        689
-------------------------------------------------------------------
Total                                              $704       $689
===================================================================

     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 1999 and 1998. It is anticipated that the 2000 requirement
will be satisfied by certifying property additions. Sinking fund requirements
and/or maturities through 2004 applicable to long-term debt are as follows: $0.7
million in 2000; $30.6 million in 2001; $0.5 million in 2002; $20.4 million in
2003; and $0.4 million in 2004.

9.  COMMON STOCK DIVIDEND RESTRICTIONS

The Company's Indenture contains certain limitations on the payment of cash
dividends on common stock. At December 31, 1999, approximately $68 million of
retained earnings was restricted against the payment of cash dividends on common
stock under the terms of the Indenture.

10.  QUARTERLY FINANCIAL INFORMATION
     (UNAUDITED)

Summarized quarterly financial data for 1999 and 1998 are as follows (in
thousands):

                                                Net Income After
                        Operating    Operating      Dividends on
Quarter Ended            Revenues      Income     Preferred Stock
------------------------------------------------------------------

March 1999                $47,098     $ 5,637         $ 1,209
June 1999                  61,692      12,495           5,268
September 1999             91,849      27,081          13,705
December 1999              50,955       4,850           2,901

March 1998                $48,381     $ 8,277         $ 2,426
June 1998                  69,616      17,269           7,807
September 1998             84,224      24,777          12,518
December 1998              52,234       3,824             893
------------------------------------------------------------------

     The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.

     The quarterly operating income information above has been reclassified to
reflect the Company's current presentation of income tax expense.



                                       II-194


<PAGE>

<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Savannah Electric and Power Company 1999 Annual Report

--------------------------------------------------------------------------------------------------------------------------------
                                                           1999            1998            1997            1996            1995
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>             <C>             <C>             <C>             <C>
Operating Revenues (in thousands)                      $251,594        $254,455        $226,277        $234,074        $225,729
Net Income after Dividends
  on Preferred Stock (in thousands)                     $23,083         $23,644         $23,847         $23,940         $23,395
Cash Dividends
  on Common Stock (in thousands)                        $25,200         $23,500         $20,500         $19,600         $17,600
Return on Average Common Equity (percent)                 13.16           13.45           13.71           14.08           14.20
Total Assets (in thousands)                            $570,218        $555,799        $547,352        $544,900        $524,662
Gross Property Additions (in thousands)                 $29,833         $18,071         $18,846         $28,950         $26,503
--------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                    $174,847        $175,865        $175,631        $172,284        $167,812
Preferred stock                                               -               -          35,000          35,000          35,000
Company obligated mandatorily
  redeemable preferred securities                        40,000          40,000               -               -               -
Long-term debt                                          147,147         163,443         142,846         164,406         153,679
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)          $361,994        $379,308        $353,477        $371,690        $356,491
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                        48.3            46.4            49.7            46.4            47.1
Preferred stock                                               -               -             9.9             9.4             9.8
Company obligated mandatorily
  redeemable preferred securities                          11.0            10.5               -               -               -
Long-term debt                                             40.7            43.1            40.4            44.2            43.1
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)             100.0           100.0           100.0           100.0           100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
    Moody's                                                  A1              A1              A1              A1              A1
    Standard and Poor's                                      AA-             AA-             AA-              A+              A+
Preferred Stock -
    Moody's                                                   a2              a2              a2              a2              a2
    Standard and Poor's                                       A-               A               A               A               A
================================================================================================================================
Customers (year-end):
Residential                                             112,891         110,437         109,092         106,657         104,624
Commercial                                               15,433          15,328          14,233          13,877          13,339
Industrial                                                   67              63              64              65              65
Other                                                       417             377           1,129           1,097           1,048
--------------------------------------------------------------------------------------------------------------------------------
Total                                                   128,808         126,205         124,518         121,696         119,076
================================================================================================================================
Employees (year-end):                                       533             542             535             571             584
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>







                                                                  II-195
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Savannah Electric and Power Company 1999 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                        1999            1998            1997            1996            1995
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>              <C>             <C>            <C>              <C>
Operating Revenues (in thousands):
Residential                                        $ 112,371        $109,393        $ 96,587       $ 101,607        $ 95,208
Commercial                                            88,449          86,231          78,949          80,494          75,117
Industrial                                            32,233          37,865          35,301          37,077          36,040
Other                                                  9,212           8,838           8,621           8,804           8,386
-----------------------------------------------------------------------------------------------------------------------------
Total retail                                         242,265         242,327         219,458         227,982         214,751
Sales for resale  - non-affiliates                     3,395           4,548           3,467           1,998           1,851
Sales for resale  - affiliates                         4,151           3,016           2,052           3,130           7,200
-----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity             249,811         249,891         224,977         233,110         223,802
Other revenues                                         1,783           4,564           1,300             964           1,927
-----------------------------------------------------------------------------------------------------------------------------
Total                                               $251,594        $254,455        $226,277        $234,074        $225,729
=============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential                                        1,579,068       1,539,792       1,428,337       1,456,651       1,402,148
Commercial                                         1,287,832       1,236,337       1,156,078       1,141,218       1,099,570
Industrial                                           713,448         900,012         881,261         838,753         887,141
Other                                                132,555         131,142         124,490         126,215         126,057
-----------------------------------------------------------------------------------------------------------------------------
Total retail                                       3,712,903       3,807,283       3,590,166       3,562,837       3,514,916
Sales for resale  - non-affiliates                    51,548          53,294          94,280          91,610          87,747
Sales for resale  - affiliates                        76,988          58,415          54,509          41,808          63,731
-----------------------------------------------------------------------------------------------------------------------------
Total                                              3,841,439       3,918,992       3,738,955       3,696,255       3,666,394
=============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                             7.12            7.10            6.76            6.98            6.79
Commercial                                              6.87            6.97            6.83            7.05            6.83
Industrial                                              4.52            4.21            4.01            4.42            4.06
Total retail                                            6.52            6.36            6.11            6.40            6.11
Sales for resale                                        5.87            6.77            3.71            3.84            5.98
Total sales                                             6.50            6.38            6.02            6.31            6.10
Residential Average Annual
  Kilowatt-Hour Use Per Customer                      14,100          14,061          13,231          13,771          13,478
Residential Average Annual
  Revenue Per Customer                             $1,003.39         $998.94         $894.73         $960.58         $915.15
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                         788             788             788             788             788
Maximum Peak-Hour Demand (megawatts):
Winter                                                   719             582             625             666             630
Summer                                                   875             846             802             811             811
Annual Load Factor (percent)                            51.2            54.9            54.3            53.1            52.9
Plant Availability Fossil-Steam (percent):              72.8            72.9            93.7            77.6            83.3
-----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                    44.6            41.6            34.4            27.7            23.9
Oil and gas                                             12.3            12.9             5.2             3.1             5.9
Purchased power -
  From non-affiliates                                    5.3             3.4             1.4             2.1             2.3
  From affiliates                                       37.8            42.1            59.0            67.1            67.9
-----------------------------------------------------------------------------------------------------------------------------
Total                                                  100.0           100.0           100.0           100.0           100.0
=============================================================================================================================
</TABLE>



                                                                  II-196




<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 2000
annual meeting of stockholders.  The ages of directors and executive officers in
Item 10 set forth below are as of December 31, 1999.

Item 10.  DIRECTORS AND EXECUTIVE
          OFFICERS OF THE REGISTRANTS

             ALABAMA

Identification of directors of ALABAMA.

Elmer B. Harris (1)
President and Chief Executive Officer
Age 60
Served as Director since 3-1-89

Whit Armstrong (2)
Age 52
Served as Director since 9-24-82

David J. Cooper, Sr. (2)
Age 54
Served as Director since 4-24-98

H. Allen Franklin (2)
Age 55
Served as Director since 10-22-99

R. Kent Henslee (2)
Age 64
Served as Director since 10-22-99

Carl E. Jones, Jr. (2)
Age 59
Served as Director since 4-22-88

Patricia M. King (2)
Age 54
Served as Director since 7-25-97

James K. Lowder  (2)
Age 50
Served as Director since 7-25-97

Wallace D. Malone, Jr. (2)
Age 63
Served as Director since 6-22-90

Thomas C. Meredith (2)
Age 58
Served as Director since 10-23-98

Mayer Mitchell (2)
Age 66
Served as Director since 10-22-99

William V. Muse (2)
Age 60
Served as Director since 2-26-93

John T. Porter (2)
Age 68
Served as Director since 10-22-93

Robert D. Powers (2)
Age 49
Served as Director since 1-24-92

Andreas Renschler (2)
Age 41
Served as Director since 1-23-98

C. Dowd Ritter (2)
Age 52
Served as Director since 7-25-97

James H. Sanford (2)
Age 55
Served as Director since 8-1-83

John C. Webb, IV (2)
Age 57
Served as Director since 4-22-77

(1)    Previously served as Director of ALABAMA from 1980 to 1985.
(2)    No position other than Director.

    Each of the above is currently a director of ALABAMA, serving a term running
from the last annual meeting of ALABAMA's stockholder (April 23, 1999) for one
year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Franklin,  Mr. Henslee and Mr. Mitchell,  whose
elections were effective on the date indicated.

                                      III-1
<PAGE>


    There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of ALABAMA acting solely in their capacities as such.

Identification of executive officers of ALABAMA.

Elmer B. Harris (1)
President, Chief Executive Officer and Director
Age 60
Served as Executive Officer since 3-1-89

Banks H. Farris
Executive Vice President
Age 64
Served as Executive Officer since 12-3-91

Michael D. Garrett
Executive Vice President
Age 50
Served as Executive Officer since 3-1-98

William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 56
Served as Executive Officer since 12-3-91

C. Alan Martin
Executive Vice President
Age 51
Served as Executive Officer since 1-1-00

Jerry L. Stewart
Senior Vice President
Age 50
Served as Executive Officer since 7-23-99

 (1)  Previously served as executive officer of ALABAMA from 1979 to 1985.

    Each of the above is currently an executive officer of ALABAMA, serving a
term running from the last annual meeting of the directors (April 23, 1999) for
one year until the next annual meeting or until his successor is elected and
qualified, except for Mr. Martin and Mr. Stewart, whose elections were effective
on the dates 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 an officer,  other than any arrangements or  understandings  with officers of
ALABAMA acting solely in their capacities as such.

Identification of certain significant employees.
         None.

Family relationships.
         None.

Business experience.

Elmer B. Harris - President and Chief Executive Officer since 1989.  Director
of SOUTHERN and AmSouth Bancorporation.

Whit Armstrong - President, Chairman of the Board and Chief Executive Officer of
The Citizens Bank, Enterprise,  Alabama. Also, President, Chairman of the Board
and Chief Executive Officer of Enterprise Capital Corporation, Inc.

David J. Cooper, Sr. - President of Cooper/T. Smith Corporation, a maritime
company with a core business of stevedoring and tugboats.  Director of Cooper/T.
Smith Corporation and subsidiaries.  Chairman of the Board, American Equity
Underwriters, Inc., Mobile, Alabama.

H. Allen Franklin - President and Chief Operating Officer of SOUTHERN.  He
previously served as President and Chief Executive Officer of GEORGIA from 1994
to 1999.  Director of GEORGIA and GULF.

R. Kent Henslee - Managing Partner of the law firm of Henslee, Robertson &
Strawn, L.L.C., Gadsden, Alabama.

Carl E. Jones, Jr. - President and Chief Executive Officer of Regions Financial
Corporation, Birmingham, Alabama.

Patricia M. King - President and Chief Executive Officer of King Motor Co.,
Inc., King's Highway, Inc. and King Imports, Inc., Anniston, Alabama.

James K. Lowder - President and Chief Executive Officer of The Colonial Company
(real estate development and sales), Montgomery, Alabama.

                                     III-2
<PAGE>


Wallace D. Malone, Jr. - Chairman and Chief Executive Officer of SouthTrust
Corporation, bank holding company, Birmingham, Alabama.

Thomas C. Meredith -  Chancellor of The University of Alabama System,
Tuscaloosa, Alabama.  Director of ATMOS Energy Corporation, Dallas, Texas.

Mayer Mitchell - President of Mitchell Brothers, Inc. (real estate and
investments), Mobile, Alabama.  Director of The Banc Corporation, Birmingham,
Alabama.

William V. Muse - President of Auburn University, Auburn, Alabama.

John T. Porter  - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama.

Robert D. Powers - President of The Eufaula Agency, Inc. (real estate and
insurance), Eufaula, Alabama.

Andreas Renschler - President of Mcc smart Gmbh,  Germany, a division of Daimler
Chrysler.

C. Dowd Ritter - Chairman, President, Chief Executive Officer of AmSouth
Bancorporation and AmSouth Bank, Birmingham, Alabama.

James H. Sanford - Chairman, HOME Place Farms Inc. (diversified farmers and
ginners), Prattville, Alabama.  President, Autauga Quality Cotton Association,
Prattville, Alabama.  Chairman of the Board, Sylvest Farms of Georgia, Inc.,
College Park, Georgia. Chairman of the Board, Sylvest Farms, Inc., Montgomery,
Alabama.

John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber and
wood products sales), Demopolis, Alabama.

Banks H.  Farris -  Executive Vice  President - Customer  Service since 1994.
Responsible for providing the overall management of human resources, information
resources, power delivery and marketing departments, customer service centers
and the six geographic divisions.

Michael D. Garrett - Executive Vice President - External Affairs since 1998. He
previously served as Senior Vice President of External Affairs from February
1994 to March  1998.  Responsible for governmental relations, environmental,
public relations,  economic development,  corporate real estate and corporate
services.

William B. Hutchins,  III - Executive Vice President and Chief Financial Officer
since 1991. Treasurer was added to his responsibilities in 1998. Responsible for
financial and accounting operations, corporate planning and treasury operations.

C. Alan Martin - Executive Vice President - External Affairs since January 2000.
He previously served as Executive Vice President and Chief Marketing Officer for
SOUTHERN from 1998 to 1999. Responsible for governmental relations,
environmental, public relations, economic development, corporate real estate and
corporate services.

Jerry L.  Stewart - Senior Vice  President - Fossil and Hydro Generation since
1999. He previously served as Vice President of Fuel Services for SCS from 1992
to 1999.  Responsible for providing overall management of the Fossil Generation,
Hydro Generation, Power Generation Support and Fuels Department.

Involvement in certain legal proceedings.
        None.

                                     III-3


<PAGE>


         GEORGIA

Identification of directors of GEORGIA.

David M. Ratcliffe
President and Chief Executive Officer
Age 51
Served as Director since 6-1-99

Daniel P. Amos (1)
Age 48
Served as Director since 5-21-97

Juanita P. Baranco (1)
Age 50
Served as Director since 5-21-97

William A. Fickling, Jr. (1)
Age 67
Served as Director since 4-18-73

H. Allen Franklin (1)
Age 55
Served as Director since 1-1-94

L. G. Hardman III (1)
Age 60
Served as Director since 6-25-79

James R. Lientz, Jr. (1)
Age 56
Served as Director since 7-21-93

Zell Miller (1)
Age 68
Served as Director since 2-17-99

G. Joseph Prendergast (1)
Age 54
Served as Director since 1-20-93

Herman J. Russell (1)
Age 69
Served as Director since 5-18-88

William Jerry Vereen (1)
Age 59
Served as Director since 5-18-88

Carl Ware (1) (2)
Age 56
Served as Director since 2-15-95

(1)    No position other than Director.
(2)    Previously served as Director of GEORGIA
       from 1980 to 1991.

    Each of the above is currently a director of GEORGIA, serving a term running
from the last annual meeting of GEORGIA's stockholder (May 19, 1999) for one
year until the  next annual meeting  or until a successor is elected and
qualified, except for Mr. Ratcliffe, who was elected 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 or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of GEORGIA acting solely in their capacities as such.

Identification of executive officers of GEORGIA.

David M. Ratcliffe
President, Chief Executive Officer and Director
Age 51
Served as Executive Officer since 3-1-98

William C. Archer, III
Executive Vice President - External Affairs
Age 51
Served as Executive Officer since 4-6-95

Thomas A. Fanning
Executive Vice President, Treasurer and
Chief Financial Officer
Age 42
Served as Executive Officer since 6-12-99

Gene R. Hodges
Executive Vice President - Customer Operations
Age 61
Served as Executive Officer since 11-19-86

Wayne T. Dahlke
Senior Vice President - Power Delivery
Age 58
Served as Executive Officer since 4-19-89

                                     III-4

<PAGE>


James K. Davis
Senior Vice President - Corporate Relations
Age 59
Served as Executive Officer since 10-1-93

Robert H. Haubein
Senior Vice President - Fossil/Hydro Power
Age 59
Served as Executive Officer since 2-19-92

Leonard J. Haynes
Senior Vice President - Marketing
Age 49
Served as Executive Officer since 10-13-98

Fred D. Williams
Senior Vice President - Resource Policy & Planning
Age 55
Served as Executive Officer since 11-18-92

    Each of the above is currently an executive officer of GEORGIA,  serving a
term running from the last annual meeting of the  directors (May 19, 1999) for
one year until the next annual meeting or until his  successor  is elected and
qualified, except for Mr. Fanning, who was elected 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 an officer,  other than any arrangements or understandings with officers of
GEORGIA acting solely in their capacities as such.

Identification of certain significant employees.
         None.

Family relationship
         None.

Business experience.

David M. Ratcliffe - President and Chief Executive Officer of GEORGIA since June
1999.  He previously served as Executive Vice President,  Treasurer and Chief
Financial Officer from 1998 to 1999.  Senior Vice President of External Affairs
for SOUTHERN from 1995 to 1998. Director of Mississippi Chemical Corporation.

Daniel P. Amos - President and Chief  Executive Officer, American Family Life
Assurance Company, Incorporated (AFLAC),  Columbus,  Georgia.  Director, AFLAC
Incorporated  (and subsidiaries),  CIT Group and Greystone Capital  Partners,
I.L.P.

Juanita P. Baranco - Business owner of Baranco Automotive Group.  Director of
Federal Reserve Bank of Atlanta and John H. Harland Company, Decatur, Georgia.

William A. Fickling,  Jr. - Chairman of the Board, Chief Executive Officer of
Beech Street Corporation (provider of managed care services) since 1989.  He
previously served as President from 1995 to 1996.

H. Allen Franklin - President and Chief Operating Officer of SOUTHERN since
1999.  He previously served as President and Chief Executive Officer of GEORGIA
from 1994 to 1999.  Director of ALABAMA and GULF.

L. G. Hardman III - Chairman of the Board and Chief Executive Officer of First
Commerce Bancorp, Inc.  Chairman of the Board of The First National Bank of
Commerce, Georgia and Chairman of the Board, President and Treasurer of
Harmony Grove Mills, Inc. (real estate investments).  Director of SOUTHERN.

James R. Lientz, Jr. - President, Bank of America (formerly NationsBank)
Mid-South Banking Group since 1993.  Director of Cerulean Companies, Inc. and
Blue Cross/Blue Shield of Georgia.

Zell Miller - Former Governor of Georgia. He served two terms as Governor of the
State of  Georgia, leaving office in January  1999.  He  previously served as
Lieutenant Governor of Georgia.  Director of Albany-based Gray Communications,
Atlanta-based  Post Properties,  Atlanta-based Law Companies Group and United
Community Banks, Inc., Blairsville, GA.

G. Joseph Prendergast - President and Chief Operating Officer, Wachovia
Corporation and Wachovia Bank, N.A., Winston Salem, North Carolina since April
1999.  He previously served as Senior Executive Vice President, Wachovia
Corporation, heading the banking division comprising the companies' consumer
and corporate banking activities and Wachovia Bank, N.A.  Director of Willamette
Industries, Inc.

                                      III-5

<PAGE>


Herman J. Russell - Chairman and Chief Executive Officer of H. J. Russell &
Company (construction), Atlanta, Georgia.  Chairman of the Board, Citizens
Trust Bank, Atlanta, Georgia.  Director of Citizens Bancshares Corporation and
National Service Industries, Atlanta, Georgia.

William Jerry Vereen - President, Treasurer, Chief Executive Officer, and
Director of Riverside Manufacturing Company (manufacture and sale of uniforms),
Moultrie, Georgia.  Director of Gerber Scientific, Inc., Textile Clothing
Technology Corporation, Cerulean Companies, Inc. and Blue Cross/Blue Shield of
Georgia.

Carl Ware - Executive Vice President, The Coca-Cola Company since January 2000.
He previously served as President, Africa Group, The Coca-Cola Company.
Director of Charlotte-based Coca-Cola Bottling Co. Consolidated.

William C.  Archer,  III - Executive Vice President - External Affairs since
September  1995.  He previously served as Senior Vice President of External
Affairs from April 1995 to September 1995. Vice President of Human Resources for
SCS from 1992 to 1995.  Responsible for governmental and regulatory affairs,
corporate  relations, land department,  environmental affairs, corporate
communications, risk management, corporate security, regulatory and litigation
support, corporate concerns and economic development.

Thomas A. Fanning - Executive Vice President, Treasurer and Chief Financial
Officer  since June 1999.  He  previously served as Senior Vice President of
Strategy for SOUTHERN from June 1998 to June 1999. Senior Vice President and
Chief Information Officer for SOUTHERN from March 1995 to 1998. Vice President,
Treasurer and Assistant Secretary  for SCS from January to March 1995.
Responsible for accounting, corporate secretary, finance and procurement.

Gene R. Hodges - Executive Vice President - Customer Operations, Power Delivery
and Safety since 1992.  Responsible for the northern and southern regions and
power delivery, customer service, region safety and labor relations' areas.

Wayne T. Dahlke - Senior Vice President - Power Delivery since 1992. Responsible
for transmission and construction, planning and projects, distribution, forestry
and right of way services and system operations.

James K. Davis - Senior Vice President - Corporate Relations since 1993.
Responsible for corporate relations and consumer affairs.

Robert H.  Haubein - Senior  Vice  President  - Fossil/ Hydro Power since 1994.
Responsible for fossil/hydro power generation, labor  relations, safety and
health.

Leonard J. Haynes - Senior Vice President - Marketing since 1998. He previously
served as Vice President of Marketing from October 1995 to November 1998.
Responsible for GEORGIA's and SAVANNAH's Power Marketing organizations as well
as SOUTHERN's national accounts organization.

Fred D. Williams - Senior Vice  President - Resource  Policy and Planning since
1997. He previously served as Senior Vice President of Wholesale Power Marketing
from 1995 to 1997.  Senior Vice President of Bulk Power Markets from 1992 to
August 1995.  Responsible for managing the supply needs for retail and wholesale
customers and developing policy and recommendations for future industry
structure.

Involvement in certain legal proceedings.
        None.



                                     III-6

<PAGE>
               GULF

Identification of directors of GULF.

Travis J. Bowden
President and Chief Executive Officer
Age 61
Served as Director since 2-1-94

Fred C. Donovan, Sr. (1)
Age 59
Served as Director since 1-18-91

H. Allen Franklin (1)
Age 55
Served as Director since 6-29-99

W. Deck Hull, Jr. (1)
Age 67
Served as Director since 10-14-83

Joseph K. Tannehill (1)
Age 66
Served as Director since 7-19-85

Barbara H. Thames (1)
Age 59
Served as Director since 2-28-97

(1)    No position other than Director.

     Each of the above is  currently a director of GULF,  serving a term running
from the last annual meeting of GULF's  stockholder (June 29, 1999) for one year
until the next annual meeting or until a successor is elected and qualified.

     There are no arrangements or understandings  between any of the individuals
listed  above and any other  person  pursuant to which he or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of GULF acting solely in their capacities as such.

Identification of executive officers of GULF.

Travis J. Bowden
President, Chief Executive Officer and Director
Age 61
Served as Executive Officer since 2-1-94

Francis M. Fisher, Jr.
Vice President - Power Delivery and Customer Operations
Age 51
Served as Executive Officer since 5-19-89

John E. Hodges, Jr.
Vice President - Marketing and Employee/External Affairs
Age 56
Served as Executive Officer since 5-19-89

Robert G. Moore
Vice President - Power Generation and Transmission
Age 50
Served as Executive Officer since 7-25-97

Arlan E. Scarbrough
Vice President - Finance
Age 63
Served as Executive Officer since 9-21-77

     Each of the above is currently an executive officer of GULF, serving a term
running from the last annual  meeting of the  directors  (July 23, 1999) for one
year  until the next  annual  meeting  or until his  successor  is  elected  and
qualified.

     There are no arrangements or understandings  between any of the individuals
listed above and any other person  pursuant to which he was or is to be selected
as an officer,  other than any arrangements or  understandings  with officers of
GULF acting solely in their capacities as such.

Identification of certain significant employees.
         None.

Family relationships.
         None.

Business experience.

Travis J. Bowden - President and Chief Executive Officer since 1994.

Fred C. Donovan, Sr. - President of Baskerville - Donovan, Inc., an
architectural and engineering firm, Pensacola, Florida.


                                      III-7


<PAGE>


H. Allen Franklin - President and Chief Operating Officer of SOUTHERN since
1999.  He previously served as President and Chief Executive Officer of GEORGIA
from 1994 to 1999.  Director of ALABAMA and GEORGIA.

W. Deck Hull, Jr. - President and Director of Hull Company, Panama City, Florida
since 1997.  He previously served as Vice Chairman of the SunTrust Bank, West
Florida, Panama City, Florida from 1993 to 1997.

Joseph K. Tannehill - President, Chairman and Chief Executive Officer of
Tannehill International Industries, Inc., Lynn Haven, Florida since 1991.
Chairman and Chief Executive Officer of Merrick Industries, Inc., Lynn Haven,
Florida since 1991.  Director of Regions Bank of North Florida, Panama City,
Florida.

Barbara H. Thames - Chief Operating Officer of West Florida Regional Medical
Center, Pensacola, Florida (a-for-profit Healthcare Corporation) since 1998. She
previously served as Chief Executive Officer of Santa Rosa Medical Center,
Milton, Florida.

Francis M. Fisher, Jr. - Vice President - Power Delivery and Customer Operations
since 1996.  He previously served as Vice President of Employee and External
Relations from 1989 to 1996.   Responsible for power delivery, customer
operations,  corporate real estate,  and total quality  management and serves as
compliance officer.

John E. Hodges, Jr. - Vice President - Marketing and  Employee/External  Affairs
since 1996. He previously  served as Vice President of Customer  Operations from
1989 to 1996. Responsible for corporate communications,  marketing, governmental
affairs,  economic development,  safety and health, employee relations and human
resources-coastal region.

Robert G. Moore - Vice President - Power Generation and Transmission of GULF and
Vice President of Fossil  Generation of SCS since 1997. He previously  served as
Plant  Manager of Plant Bowen at GEORGIA.  Responsible  for the  generation  and
transmission of electricity and bulk power marketing efforts.

Arlan E.  Scarbrough - Vice President - Finance since 1980.  Responsible for all
accounting, financial and regulatory matters.

Involvement in certain legal proceedings.
        None.



                                     III-8

<PAGE>


                MISSISSIPPI

Identification of directors of MISSISSIPPI.

Dwight H. Evans
President and Chief Executive Officer
Age 51
Served as Director since 3-27-95

Edwin E. Downer (1)
Age 68
Served as Director since 4-24-84

Robert S. Gaddis (1)
Age 68
Served as Director since 1-21-86

Linda T. Howard (1)
Age 56
Served as Director since 2-24-99

Aubrey K. Lucas (1)
Age 65
Served as Director since 4-24-84

Malcolm Portera (1)
Age 53
Served as Director since 4-6-99

George A. Schloegel (1)
Age 59
Served as Director since 7-26-95

Philip J. Terrell (1)
Age 46
Served as Director since 2-22-95

N. Eugene Warr (1)
Age 64
Served as Director since 1-21-86

(1)    No position other than Director.

    Each of the above is currently a director of MISSISSIPPI, serving a term
running from the last annual meeting of  MISSISSIPPI's  stockholder (April 6,
1999) for one year until the next annual meeting or until a successor is elected
and qualified.

    There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of MISSISSIPPI acting solely in their capacities as
such.

Identification of executive officers of MISSISSIPPI.

Dwight H. Evans
President, Chief Executive Officer and Director
Age 51
Served as Executive Officer since 3-27-95

H. E. Blakeslee
Vice President - Customer Services and Retail Marketing
Age 59
Served as Executive Officer since 1-25-84

Mark S. Lynch
Vice President - Power Generation and Delivery
Age 46
Served as Executive Officer since 10-1-99

Don E. Mason
Vice President - External Affairs and Corporate Services
Age 58
Served as Executive Officer since 7-27-83

Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
Age 47
Served as Executive Officer since 1-1-95

    Each of the above is currently an executive officer of MISSISSIPPI, serving
a term running from the last annual meeting of the directors (April 28, 1999)
for one year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Lynch, who was elected 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 an officer,  other than any arrangements or understandings with officers of
MISSISSIPPI acting solely in their capacities as such.


                                     III-9

<PAGE>



Identification of certain significant employees.
         None.

Family relationships.
        None.

Business experience.

Dwight H. Evans - President and Chief Executive Officer since 1995.  He
previously served as Executive Vice President of External Affairs of GEORGIA
from 1989 to 1995.

Edwin E. Downer -  Business consultant specializing in economic analysis,
management controls and procedural studies, Meridian, Mississippi.

Robert S. Gaddis - Chairman of the Advisory Board of Trustmark National Bank,
Laurel, Mississippi.

Linda T. Howard - President of Howard Industries, Inc., Laurel, Mississippi.

Aubrey K. Lucas -  President Emeritus and Distinguished Professor of Higher
Education at the University of Southern Mississippi, Hattiesburg, Mississippi.

Malcolm Portera - President, Mississippi State University, Starkville,
Mississippi.

George A. Schloegel - President and Chief Executive Officer of Hancock Bank.
President, Chief Executive Officer and Director of Hancock Bank Securities
Corporation.  Vice Chairman of Hancock Holding Company.  Director of Hancock
Bank of Mississippi and Hancock Bank of Louisiana.

Philip J. Terrell -  Superintendent of Schools, Pass Christian Public School
District,  Pass Christian,  Mississippi; and adjunct Professor of Education at
William Carey College, Gulfport, Mississippi.

N. Eugene Warr - Retailer, Gulfport, Mississippi.  Director of Coast
Community Bank, formerly SouthTrust Bank of Mississippi, Biloxi,
Mississippi.

H. E. Blakeslee - Vice President - Customer Services and Retail Marketing
since 1984.  Responsible for rate design, revenue forecasting, marketing,
district operations, corporate compliance, distribution engineering, customer
accounting, vehicle maintenance centers and customer call center.

Mark S. Lynch - Vice  President - Power Generation and Delivery since 1999. He
previously served as President and Chief Executive Officer of Empresa Electrica
del Norte Grande,  S.A. from 1996 to 1999.  Responsible for generating  plants,
environmental quality,  fuel services, power generation technical services,
transmission, system planning, bulk power contracts, system operations and
control, system protection and real estate.

Don E. Mason - Vice  President - External Affairs and Corporate Services since
1983. Responsible for external affairs, corporate communications, security, risk
management, economic development and general services, as well as the human
resources function.

Michael W. Southern - Vice President,  Secretary, Treasurer and Chief Financial
Officer since 1995. He previously served as Director of Corporate Finance of SCS
from 1994 to 1995.  Responsible for accounting, secretary/treasury, corporate
planning, procurement and information resources.

Involvement in certain legal proceedings.
        None.

                                     III-10
<PAGE>


           SAVANNAH

Identification of directors of SAVANNAH.

G. Edison Holland, Jr.
President and Chief Executive Officer
Age 47
Served as Director since 7-15-97

Gus H. Bell (1)
Age 62
Served as Director since 7-20-99

Archie H. Davis (1)
Age 58
Served as Director since 2-18-97

Walter D. Gnann (1)
Age 64
Served as Director since 5-17-83

Robert B. Miller, III (1)
Age 54
Served as Director since 5-17-83

Arnold M. Tenenbaum (1)
Age 63
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 18, 1999)
for one year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Bell, who was elected 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 or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with  directors or officers of SAVANNAH  acting  solely in their capacities as
such.

Identification of executive officers of SAVANNAH.

G. Edison Holland, Jr.
President, Chief Executive Officer and Director
Age 47
Served as Executive Officer since 7-15-97

Lewis A. Jeffers
Vice President - Power Generation
Age 44
Served as Executive Officer since 11-2-99

W. Miles Greer
Vice President - Customer Operations and External Affairs
Age 56
Served as Executive Officer since 11-20-85

Kirby R. Willis
Vice President, Treasurer, Chief Financial Officer
and Assistant Corporate Secretary
Age 48
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 20, 1999 for the
ensuing year, except for Mr. Jeffers who was elected 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 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.

Business experience.

G. Edison Holland, Jr. - President and Chief Executive Officer since 1997.  He
previously served as Vice President of Power Generation/Transmission and
Corporate Counsel of GULF from 1995 to 1997.  Served as a partner in the law
firm of Beggs & Lane from 1979 to 1997.  Director of SunTrust Bank of Savannah.

Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell
and DeYoung, Inc., (specializing in environmental, industrial, structural,
architectural and civil engineering), Savannah, Georgia.  Director of SunTrust
Bank of Savannah.


                                     III-11

<PAGE>

Archie H. Davis - President and Chief Executive Officer of
The Savannah Bancorp and The Savannah Bank, N.A., Savannah, Georgia.  Member of
the Board of Directors of Thomaston Mills, Thomaston, Georgia..

Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc.,
Springfield, Georgia.

Robert B. Miller, III - President of American Building Systems, Inc., Savannah,
Georgia.

Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation.
Director of First Union Bank of Georgia, First Union Bank of Savannah and
Cerulean Corporation.

W. Miles Greer - Vice President - Customer Operations and External Affairs since
1998. He previously  served as Vice President of Marketing and Customer Service
from 1994 to 1998. Responsible for customer services, transmission and
distribution, engineering, system operation and external affairs.

Lewis A. Jeffers - Vice President - Power  Generation since 1999. He previously
served as General  Manager of Power Generation from February 1999 to November
1999;  General Manager for Plants Smith and Scholz at GULF from May 1996 through
January 1999;  and Assistant General Manager at ALABAMA for Plant Barry from
September 1993 to May 1996. Responsible for operations and maintenance of Plants
Kraft, Riverside and McIntosh.

Kirby R. Willis - Vice President,  Treasurer and Chief  Financial  Officer since
1994 and Assistant Corporate Secretary effective 1998. Responsible primarily for
accounting,   financial,   labor  relations,   corporate   services,   corporate
compliance, environmental and safety activities.

Involvement in certain legal proceedings.
       None

Section 16(a) Beneficial Ownership Reporting
Compliance.

MISSISSIPPI's Mr. Lynch filed an Initial Statement of Beneficial Ownership of
Equity Securities on Form 3, late.

                                     III-12



<PAGE>

Item 11.        EXECUTIVE COMPENSATION

Summary Compensation Tables. The following tables set forth information
concerning any Chief Executive Officer and the four most highly compensated
executive officers whose total annual salary and bonus exceeded $100,000 during
1999 for each of the integrated Southeast utilities (ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH).

Key terms used in this Item will have the following meanings:-

AME.............................Above-market earnings on deferred compensation
ESP.............................Employee Savings Plan
ESOP............................Employee Stock Ownership Plan
SBP.............................Supplemental Benefit Plan
ERISA...........................Employee Retirement Income Security Act

<TABLE>
<CAPTION>

                                     ALABAMA
                           SUMMARY COMPENSATION TABLE

                                          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>
Elmer B. Harris
President,             1999      550,674       97,125          15,301           31,341        330,618          29,800
Chief Executive        1998      545,102      192,751          19,060           29,411        249,971          30,180
Officer,               1997      500,700      101,002          20,453           35,648        247,224          30,172
Director

Banks H. Farris        1999      306,954       46,723          16,342           13,485        205,980          16,439
Executive Vice         1998      275,822       32,631           8,530           11,473        178,829          14,764
President              1997      247,170       37,500           7,218           13,513        155,313          14,379

William B.
   Hutchins, III
Executive Vice          1999     256,665       36,365           9,573           11,246        152,585          13,804
President,              1998     237,532       34,646           3,010            8,118        132,472          12,678
Chief Financial         1997     217,756       31,400           1,383            9,834        115,170          12,441
Officer






</TABLE>

See next page for footnotes.

                                     III-13
<PAGE>
<TABLE>
<CAPTION>


                                     ALABAMA
                           SUMMARY COMPENSATION TABLE
                                   (Continued)



                                              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>
Michael D. Garrett 4   1999         256,211       36,375           21,268         11,249        132,434        13,496
Executive Vice         1998         221,731       57,026           12,389          7,800        105,866        11,558
President              1997               -            -                -              -              -             -


Jerry L. Stewart4       1999        182,097       26,996            1,884          6,340        122,003         9,794
Senior Vice President   1998              -            -                -              -              -             -
                        1997              -            -                -              -              -             -



1 Tax reimbursement by ALABAMA and certain personal benefits.
2    Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997, 1998 and 1999,
respectively.
3    ALABAMA contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan under
which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for the following:-
Name ESP                           ESOP              SBP
Elmer B. Harris                   $5,691               $897           $23,212
Banks H. Farris                    7,401                897             8,141
William B. Hutchins, III           6,603                897             6,304
Michael D. Garrett                 5,691                897             6,908
Jerry L. Stewart                   7,200                897             1,697
4    Messrs. Garrett and Stewart were named executive officers effective April 24, 1998 and July 23, 1999, respectively.


</TABLE>
                                     III-14
<PAGE>
<TABLE>
<CAPTION>




                                     GEORGIA
                           SUMMARY COMPENSATION TABLE

                                              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>
H. Allen Franklin 4
President,              1999        603,658        126,000         31,023         71,153        375,137        32,654
Chief Executive         1998        564,329        237,502          7,078         30,521        283,629        31,590
Officer, Director       1997        511,505        129,426         14,219         36,544        280,513        31,350

David M. Ratcliffe
President,              1999        388,819         85,389         16,051         24,110        321,983        20,885
Chief Executive         1998        339,672         62,700          3,934         14,039        218,175        12,255
Officer, Director       1997        313,152         50,515         10,828         17,086        207,322        18,342

Robert H.               1999        278,502         59,882         11,801         11,209        152,585        13,693
 Haubein, Jr.           1998        239,448         35,683          1,922          8,175        132,472        13,007
Senior Vice President   1997        220,358         35,683            657          9,952        115,170        11,981

Gene R. Hodges          1999        243,487         44,086         12,538         10,604        152,585        13,259
Executive               1998        244,284         42,595          4,543          8,317        132,472        13,087
Vice President          1997        228,336         39,058          5,544         10,271        126,075        13,111

Thomas A. Fanning 5
Executive Vice
President, Treasurer    1999        233,644         48,312          4,504         10,458        152,585        12,396
and Chief               1998              -              -              -              -              -             -
Financial Officer       1997              -              -              -              -              -             -

William C. Archer       1999        220,706         40,120         16,609          7,972        152,585        11,844
Executive               1998        216,246        121,261         67,940          7,390        132,472        11,404
Vice President          1997        197,870         40,054          3,410          8,953         84,048        11,280

1    Tax reimbursement by GEORGIA on certain personal benefits, including $64,679 in 1998 for Mr. Archer related to a cash award.
2    Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997, 1998 and 1999,
respectively.
3    GEORGIA contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan
under which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for the following:-
Name                                ESP               ESOP               SBP
H. Allen Franklin                 $6,242                $897          $25,515
David M. Ratcliffe                 7,301                 897           12,687
Robert H. Haubein, Jr.             6,647                 897            6,149
Gene R. Hodges                     7,200                 897            5,162
Thomas A. Fanning                  7,200                 897            4,299
William C. Archer                  5,838                 897            5,109
4    Mr. Franklin resigned as President and Chief Executive Officer of GEORGIA to become Chief Operating Officer of SOUTHERN
effective June, 1999.  He was replaced by Mr. Ratcliffe effective June, 1999.
5    Mr. Fanning was named an executive officer effective June 12, 1999.

</TABLE>


                                     III-15
<PAGE>
<TABLE>
<CAPTION>


                                      GULF
                           SUMMARY COMPENSATION TABLE

                                              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>
Travis J. Bowden
President,             1999          332,482        40,229         10,199          14,514        251,300       18,171
Chief Executive        1998          329,280        35,121          3,839          13,583        218,175       18,068
Officer, Director      1997          306,584        33,933          2,842          16,694        207,322       17,888

Arlan E. Scarbrough    1999          199,142        14,839          6,557           7,181        111,258       10,641
Vice President         1998          196,661        18,071          3,253           6,721         96,594       10,218
                       1997          180,642        18,212          1,440           8,142         84,048       10,235

John E. Hodges, Jr.    1999          194,832        14,518          8,556           7,026        111,258       10,470
Vice President         1998          192,765        17,680            915           6,575         96,594       10,014
                       1997          178,428        17,989          2,418           8,042         91,977       10,185

Francis M.             1999          177,934        13,259          6,508           6,417        111,258        9,558
 Fisher, Jr.           1998          175,719        16,147            240           6,005         96,594        9,329
Vice President         1997          160,783        16,274            479           7,275         84,048        9,182

Robert G. Moore        1999          161,641        22,981         13,949           5,829         97,722        8,569
Vice President         1998          159,332        18,626            525           4,881         72,767        8,325
                       1997          149,926        23,474              -           4,741         46,551        7,550


1    Tax reimbursement by GULF on certain personal benefits.
2    Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997,
1998 and 1999, respectively.
3    GULF contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan under
which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for the following:-
Name                                ESP               ESOP             SBP
Travis J. Bowden                   $6,779               $897         $10,495
Arlan E. Scarbrough                 6,526                897           3,218
John E. Hodges, Jr.                 6,390                897           3,183
Francis M. Fisher, Jr.              6,276                897           2,385
Robert G. Moore                     6,699                897             973

</TABLE>


                                     III-16
<PAGE>

<TABLE>
<CAPTION>

                                   MISSISSIPPI
                           SUMMARY COMPENSATION TABLE

                                              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>
Dwight H. Evans
President, Chief       1999         288,494       43,702            3,375         12,614         251,300       15,507
Executive              1998         283,195       42,603            5,051         11,693         218,175       15,291
Officer, Director      1997         262,678       39,643            3,830         14,303         126,075       15,025

H. E. Blakeslee        1999         207,769       37,649            8,070          7,481         111,258       11,254
Vice President         1998         207,416       36,202               47          7,068          96,594       10,979
                       1997         192,029       38,863              697          8,687          91,977       10,991

Andrew J.
 Dearman, III 4        1999         173,490       71,648           10,527          5,843         103,585        8,543
Vice President         1998         159,713       41,031              600          4,893          83,087        8,343
                       1997         141,393       21,008            2,083          5,871          42,903       21,354

Don E. Mason           1999         203,584       36,891              821          7,330         111,258       10,243
Vice President         1998         203,234       29,560            4,497          6,926          96,594       10,757
                       1997         188,126       41,889              839          8,512          84,048       10,675

Michael W. Southern
Vice President
Chief Financial        1999         189,117       34,369            8,891          6,469         103,585        9,590
Officer, Secretary,    1998         174,334       34,130                -          5,997          83,087        8,978
Treasurer              1997         155,151       31,406            1,590          6,281          65,768        8,757

Mark S. Lynch 5        1999         174,833       18,940               16          6,178         111,258        9,566
Vice President         1998               -            -                -              -               -            -
                       1997               -            -                -              -               -            -


1    Tax reimbursement by MISSISSIPPI on certain personal benefits.
2    Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997,
1998 and 1999, respectively.
3    MISSISSIPPI contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan
under which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for the following:-
Name                                     ESP              ESOP               SBP
Dwight H. Evans                        $6,697             $897             $7,913
H. E. Blakeslee                         5,691              897              4,666
Andrew J. Dearman, III                  6,567              897              1,079
Don E. Mason                            5,691              897              3,655
Michael W. Southern                     5,691              897              3,002
Mark S. Lynch                           7,200              897              1,469
4    Effective September 1999, Mr. Dearman transferred to Southern Energy into the position of Senior Vice President and Chief
Technical Officer.
5    Mr. Lynch was named an executive officer effective October 1, 1999.

</TABLE>

                                     III-17
<PAGE>
<TABLE>
<CAPTION>


                                       SAVANNAH
                           SUMMARY COMPENSATION TABLE

                                              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.
President,               1999       254,914       42,626           21,588         8,375         166,052        13,392
Chief Executive          1998       233,330       26,019           17,309         7,951         128,608         8,246
Officer, Director        1997       202,413       26,231            3,046         8,640          91,977        49,892

W. Miles Greer           1999       168,713       21,322            1,874         6,130          79,476        15,150
Vice President           1998       160,207       16,054               13         4,901          69,000        13,179
                         1997       138,643       16,294              805         4,924          60,636        10,740

Kirby R. Willis
Vice President,          1999       156,068       19,546              259         5,028          79,476        11,767
Chief Financial          1998       155,236       15,554               13         4,748          69,000        10,581
Officer, Treasurer       1997       134,794       15,915              182         4,809          60,636         9,322

Lewis A. Jeffers 4       1999       134,538       19,023              379         3,809          63,146         6,972
Vice President           1998             -            -                -             -               -             -
                         1997             -            -                -             -               -             -

1    Tax reimbursement by SAVANNAH on certain personal benefits, including membership fees of $11,669 for
Mr. Holland, Jr. in 1998.
2    Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997, 1998
and 1999, respectively.
3    SAVANNAH contributions to the ESP, under Section 401(k) of the Internal Revenue Code, ESOP, and SBP or AME for
the following:-
Name                                   ESP               ESOP           SBP or AME
G. Edison Holland, Jr.                $6,983              $897          $5,512
W. Miles Greer                         6,698               897             7,555
Kirby R. Willis                        5,674               897             5,196
Lewis A. Jeffers                       6,036               897                39
In 1997, Mr. Holland received a one-time lump-sum payment of $38,654, given in connection with his appointment
to his current position.
4    Mr. Jeffers was named an executive officer effective November 2, 1999.

</TABLE>
                                     III-18
<PAGE>
<TABLE>
<CAPTION>

                           STOCK OPTION GRANTS IN 1999

Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of each operating subsidiary during the year ending
December 31, 1999.


                                   Individual Grants                                         Grant Date Value

                              # of           % of Total
                              Securities     Options Exercise
                              Underlying     Granted to       or
                              Options        Employees in     Base Price      Expiration      Grant Date
   Name                       Granted1       Fiscal Year2     ($/Sh)1         Date1           Present Value($)3
    -----------------------------------------------------------------------------------------------------------

   ALABAMA

   <S>                          <C>               <C>           <C>           <C>                  <C>
   Elmer B. Harris              31,341            1.5           26.5625       05/01/2009           197,135
   Banks H. Farris              13,485            0.6           26.5625       06/01/2005            59,873
   William B. Hutchins, III     11,246            0.5           26.5625       07/19/2009            70,737
   Michael D. Garrett           11,249            0.5           26.5625       07/19/2009            70,756
   Jerry L. Stewart              6,340            0.3           26.5625       07/19/2009            39,879

   GEORGIA

   H. Allen Franklin            71,153            3.4           26.5625       07/19/2009           447,552
   David M. Ratcliffe           24,110            1.1           26.5625       07/19/2009           151,652
   Robert H. Haubein, Jr.       11,209            0.5           26.5625       07/19/2009            70,505
   Gene R. Hodges               10,604            0.5           26.5625       04/01/2008            62,352
   Thomas A. Fanning            10,458            0.5           26.5625       07/19/2009            65,781
   William C. Archer             7,972            0.4           26.5625       07/19/2009            50,144

   GULF

   Travis J. Bowden             14,514            0.7           26.5625       09/01/2008            85,342
   Arlan E. Scarbrough           7,181            0.3           26.5625       11/01/2006            35,618
   John E. Hodges, Jr.           7,026            0.3           26.5625       07/19/2009            44,194
   Francis M. Fisher, Jr.        6,417            0.3           26.5625       07/19/2009            40,363
   Robert G. Moore               5,829            0.3           26.5625       07/19/2009            36,664


   See next page for footnotes.


</TABLE>


                                     III-19
<PAGE>
<TABLE>
<CAPTION>


                                                        STOCK OPTION GRANTS IN 1999





                                   Individual Grants                                         Grant Date Value

                              # of           % of Total
                              Securities     Options Exercise
                              Underlying     Granted to       or
                              Options        Employees in     Base Price      Expiration     Grant Date
   Name                       Granted1       Fiscal Year2     ($/Sh)1         Date1          Present Value($)3
   -----------------------------------------------------------------------------------------------------------

   MISSISSIPPI

<S>                             <C>               <C>           <C>           <C>                    <C>
   Dwight H. Evans              12,614            0.6           26.5625       07/19/2009             79,342
   H. E. Blakeslee               7,481            0.4           26.5625       07/19/2009             47,055
   Andrew J. Dearman, III        5,843            0.3           26.5625       07/19/2009             36,752
   Don E. Mason                  7,330            0.3           26.5625       07/19/2009             46,106
   Michael W. Southern           6,469            0.3           26.5625       07/19/2009             40,690
   Mark S. Lynch                 6,178            0.3           26.5625       07/19/2009             38,860

   SAVANNAH

   G. Edison Holland, Jr.        8,375            0.4           26.5625       07/19/2009             52,679
   W. Miles Greer                6,130            0.3           26.5625       07/19/2009             38,558
   Kirby R. Willis               5,028            0.2           26.5625       07/19/2009             31,626
   Lewis A. Jeffers              3,809            0.2           26.5625       07/19/2009             23,959


1    Performance Stock Plan grants were made on July 19, 1999, and vest annually at a rate of one-third on the anniversary date of
the grant.  Grants fully vest upon termination because of death, total disability, or retirement and expire the earlier of five
years after such event or their normal expiration date.  The exercise price is the average of the high and low fair market value
of SOUTHERN's common stock on the date granted.  Options may be transferred to family trusts and family limited partnerships.  In
accordance with the terms of the Performance Stock Plan, Mr. Bowden's unexercised options expire on September 1, 2008, five years
after his normal retirement date; Mr. Farris' unexercised options expire on June 1, 2005, five years after his normal retirement
date; Mr. Harris' unexercised options expire on May 1, 2009, five years after his normal retirement date; Mr. Gene R. Hodges'
unexercised options expire on  April 1, 2008, five years after his normal retirement date; and Mr. Scarbrough's unexercised
options expire on November 1, 2006, five years after his normal retirement date.
2    A total of 2,108,818 stock options were granted in 1999.
3    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 used to calculate this value: price
volatility - 20.74%; risk-free rate of return - 5.79%; dividend opportunity -50%; time to exercise - 10 years; reductions for
probability of forfeiture before vesting - 7.79%; and reductions for probability of forfeiture before expiration - 13.40%.  These
assumptions reflect the effects of cash dividend equivalents paid to participants under the Performance Dividend Plan assuming
targets are met.

</TABLE>

                                     III-20
<PAGE>






AGGREGATED STOCK OPTION EXERCISES IN 1999 AND YEAR-END OPTION VALUES

Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 1999, by the
named executive officers and the value of unexercised options held by them as of
December 31, 1999.
<TABLE>
<CAPTION>

                                                                        Number of
                                                                        Securities             Value of
                                                                        Underlying             Unexercised
                                                                        Unexercised            In-the-Money
                                                                        Options at             Options at
                                                                        Fiscal                 Fiscal
                                                                        Year-End (#)           Year-End($)1

                         Shares Acquired           Value                Exercisable/           Exercisable/
Name                     on Exercise (#)           Realized($)2         Unexercisable          Unexercisable
-------------------------------------------------------------------------------------------------------------

ALABAMA

<S>                            <C>                    <C>               <C>     <C>             <C>     <C>
Elmer B. Harris                4,718                  71,802            219,394/70,733          915,188/30,688
Banks H. Farris                    -                       -             38,372/28,070           66,409/11,351
William B. Hutchins, III           -                       -             43,701/22,100           113,519/8,458
Michael D. Garrett                 -                       -             11,596/20,918            16,443/6,946
Jerry L Stewart                    -                       -             16,843/14,169            23,814/6,151

GEORGIA

H. Allen Franklin                  -                       -           191,114/111,645          700,904/31,389
David M. Ratcliffe             3,984                  53,908             85,160/42,959          307,716/14,711
Robert H. Haubein, Jr.             -                       -             37,975/22,166            81,698/8,558
Gene R. Hodges                     -                       -             38,577/21,876            81,361/8,856
Thomas A. Fanning                  -                       -             16,422/20,560            22,818/7,872
William C. Archer                  -                       -             20,538/17,833            28,079/7,690

GULF

Travis J. Bowden                   -                       -             19,094/32,878           24,772/14,393
Arlan E. Scarbrough                -                       -              9,292/16,184            12,007/7,011
John E. Hodges, Jr.                -                       -             24,796/15,877            38,885/6,926
Francis M. Fisher, Jr.             -                       -              7,853/14,264            10,158/6,166
Robert G. Moore                    -                       -             12,039/11,680            16,514/4,064



See next page for footnotes.
</TABLE>

                                     III-21
<PAGE>

<TABLE>
<CAPTION>

AGGREGATED STOCK OPTION EXERCISES IN 1999 AND YEAR-END OPTION VALUES

                                                                        Number of
                                                                        Securities             Value of
                                                                        Underlying             Unexercised
                                                                        Unexercised            In-the-Money
                                                                        Options at             Options at
                                                                        Fiscal                 Fiscal
                                                                        Year-End (#)           Year-End($)1

                         Shares Acquired           Value                Exercisable/           Exercisable/
Name                     on Exercise (#)           Realized($)2         Unexercisable          Unexercisable
--------------------------------------------------------------------------------------------------------------

MISSISSIPPI

<S>                                                                      <C>    <C>           <C>     <C>
Dwight H. Evans                    -                       -             55,961/28,385        136,976/12,332
H. E. Blakeslee                    -                       -             31,701/16,982          66,471/7,463
Andrew J. Dearman, III             -                       -             12,920/12,108          18,323/4,926
Don E. Mason                       -                       -             20,994/16,639          29,511/7,311
Michael W. Southern                -                       -             15,139/13,930          20,562/5,396
Mark S. Lynch                      -                       -             10,336/13,490          11,447/5,367

SAVANNAH

G. Edison Holland, Jr.             -                       -             40,342/18,475         105,982/7,440
W. Miles Greer                     -                       -             12,505/12,104          17,221/4,225
Kirby R. Willis                    -                       -             11,770/10,777          16,256/4,097
Lewis A. Jeffers                   -                       -                   0/3,809                   0/0


1    This represents the excess of the fair market value of SOUTHERN's common stock of $23.50 per share, as of December 31, 1999,
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, 1999.
2    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 over the exercise price.

</TABLE>

                                     III-22
<PAGE>


                   LONG-TERM INCENTIVE PLANS - AWARDS IN 1999

Long-Term Incentive Plans. The following table sets forth the long-term
incentive plan awards made to the named executive officers for the performance
period January 1, 1999 through December 31, 2002.
<TABLE>
<CAPTION>

                                                                       Estimated Future Payouts under
                                                                         Non-Stock Price-Based Plans

                                                 Performance or
                                                 Other Period
                           Number of             Until Maturation      Threshold          Target       Maximum
Name                       Units (#)1            or Payout             ($)2               ($)2          ($)2
---------------------------------------------------------------------------------------------------------------

ALABAMA

<S>                            <C>                   <C>                 <C>              <C>            <C>
Elmer B. Harris                321,879               4 years             160,940          321,879        643,758
Banks H. Farris                128,474               4 years              64,237          128,474        256,948
William B. Hutchins, III        95,170               4 years              47,585           95,170        190,340
Michael D. Garrett              82,601               4 years              41,301           82,601        165,203
Jerry L. Stewart                76,095               4 years              38,048           76,095        152,190

GEORGIA

H. Allen Franklin              438,499               4 years             219,250          438,499        876,998
David M. Ratcliffe             200,827               4 years             100,414          200,827        401,654
Robert H. Haubein, Jr.          95,170               4 years              47,585           95,170        190,340
Gene R. Hodges                  95,170               4 years              47,585           95,170        190,340
Thomas A. Fanning               95,170               4 years              47,585           95,170        190,340
William C. Archer               95,170               4 years              47,585           95,170        190,340

GULF

Travis J. Bowden               156,741               4 years              78,370          156,741        313,482
Arlan E. Scarbrough             69,394               4 years              34,697           69,394        138,788
John E. Hodges, Jr.             69,394               4 years              34,697           69,394        138,788
Francis M. Fisher, Jr.          69,394               4 years              34,697           69,394        138,788
Robert G. Moore                 60,952               4 years              30,476           60,952        121,903




</TABLE>

See next page for footnotes.

                                     III-23
<PAGE>

<TABLE>
<CAPTION>

                   LONG-TERM INCENTIVE PLANS - AWARDS IN 1999


                                                                       Estimated Future Payouts under
                                                                         Non-Stock Price-Based Plans


                                                 Performance or
                                                 Other Period
                           Number of             Until Maturation      Threshold        Target          Maximum
Name                       Units (#)1            or Payout             ($)2             ($)2            ($)2
----------------------------------------------------------------------------------------------------------------


MISSISSIPPI

<S>                          <C>                     <C>                  <C>             <C>            <C>
Dwight H. Evans              156,741                 4 years              78,370          156,741        313,482
H. E. Blakeslee               69,394                 4 years              34,697           69,394        138,788
Andrew J. Dearman, III        64,608                 4 years              32,304           64,608        129,215
Don E. Mason                  69,394                 4 years              34,697           69,394        138,788
Michael W. Southern           64,608                 4 years              32,304           64,608        129,215
Mark S. Lynch                 69,394                 4 years              34,697           69,394        138,788

SAVANNAH

G. Edison Holland, Jr.       103,570                 4 years              51,785          103,570        207,139
W. Miles Greer                49,571                 4 years              24,786           49,571         99,142
Kirby R. Willis               49,571                 4 years              24,786           49,571         99,142
Lewis A. Jeffers              39,385                 4 years              19,692           39,385         78,770

1        A performance unit is a method of assigning a dollar value to a performance award opportunity.  Under the
Executive Productivity Improvement Plan, the number of units granted to Messrs. Harris and Franklin is 65% of the average of
Messrs. Harris' and Franklin's base salary range mid-points.  All other executive officers listed in this table are participants
in the Productivity Improvement Plan of SOUTHERN, the number of units granted to these named executive officers is based on the
weighted average of the base salary mid-points as of December 31 for each calendar year in the four-year computation period.  No
awards are paid unless the participant remains employed by the company through the end of the performance period.
2    The threshold, target and maximum value of a unit is 50 percent, 100 percent and 200 percent, respectively.   These
percentages can vary based on SOUTHERN's return on common equity and total shareholder return relative to selected groups of
electric and gas utilities.  If certain minimum performance relative to the selected groups is not achieved, there will be no
payout; nor is there a payout if the current earnings of SOUTHERN are not sufficient to fund the dividend rate paid in the last
calendar year.  The Plan provides that in the discretion of the committee, extraordinary income may be excluded for purposes of
calculating the amount available for the payment of awards.  All awards are payable in cash at the end of the performance period.

</TABLE>


                                     III-24
<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 supplemental benefits, based on the stated compensation and
years of service with the SOUTHERN system for the named executives at ALABAMA,
GEORGIA, GULF and MISSISSIPPI and Mr. Holland at SAVANNAH. Compensation for
pension purposes is limited to the average of the highest three of the final 10
years' compensation -- base salary plus the excess of annual and long-term
incentive compensation over 25 percent of base salary (reported under column
titled "Salary", "Bonus", and "Long-Term Incentive Payouts" in the Summary
Compensation Tables on pages III-13 through III-18).

         The amounts shown in the table were calculated according to the final
average pay formula and are based on a single life annuity without reduction for
joint and survivor annuities (although married employees are required to have
their pension benefits paid in one of various joint and survivor annuity forms,
unless the employee elects otherwise with the spouse's consent) or computation
of the Social Security offset which would apply in most cases. This offset
amounts to one-half of the estimated Social Security benefit (primary insurance
amount) in excess of $3,900 per year times the number of years of accredited
service, divided by the total possible years of accredited service to normal
retirement age.
<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, 1999, the applicable compensation levels and years
of accredited service are presented in the following tables:


ALABAMA
                                           Compensation          Accredited
            Name                              Level            Years of Service

            Elmer B. Harris                    $878,724               40
            Banks H. Farris                     429,312               40
            William B. Hutchins, III            348,304               33
            Michael D. Garrett                  309,688               31
            Jerry L. Stewart                    257,848               26

                                     III-25
<PAGE>


GEORGIA
                                             Compensation           Accredited
            Name                                 Level          Years of Service

            H. Allen Franklin                  $967,132                  28
            David M. Ratcliffe                  583,968                  28
            Robert H. Haubein, Jr.              344,444                  32
            Gene R. Hodges                      356,788                  35
            Thomas A. Fanning                   329,728                  18
            William C. Archer                   323,200                  28

GULF
                                             Compensation          Accredited
            Name                                 Level         Years of Service

            Travis J. Bowden1                  $505,372                 33
            Arlan E. Scarbrough                 257,876                 36
            John E. Hodges, Jr.                 257,548                 33
            Francis M. Fisher, Jr.              240,780                 28
            Robert G. Moore                     210,200                 26

MISSISSIPPI
                                             Compensation           Accredited
            Name                                 Level         Years of Service

            Dwight H. Evans                    $448,124                  28
            H. E. Blakeslee                     288,660                  34
            Andrew J. Dearman, III              229,043                  24
            Don E. Mason                        281,516                  33
            Michael W. Southern                 244,592                  24
            Mark S. Lynch                       262,193                  10

SAVANNAH
                                           Compensation            Accredited
            Name                                 Level         Years of Service

            G. Edison Holland, Jr.2            $336,428                  16
            W. Miles Greer                      157,144                  15
            Kirby R. Willis                     149,479                  25
            Lewis A. Jeffers                    124,064                  20


1  The number of accredited years of service includes 10 years credited to
Mr. Bowden pursuant to a supplemental pension agreement.
2  The number of accredited years of service includes 9 years and 3 months
credited to Mr. Holland pursuant to a supplemental pension agreement.

                                     III-26
<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 1999 which are payable to SAVANNAH's named
executives, except Mr. Holland who participates in the plans described on page
III-25, 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
--------------------------         --                 --               --

         $  90,000               $ 63,000          $ 63,000         $ 63,000
           120,000                 84,000            84,000           84,000
           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
           320,000                224,000           224,000          224,000
           340,000                238,000           238,000          238,000


                                     III-27
<PAGE>


Compensation of Directors.

         Standard Arrangements. The following table presents compensation paid
to the directors, during 1999 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. All or a portion of these fees payable in cash may be deferred under
the Deferred Compensation Plan until membership on the board is terminated or
may be payable in SOUTHERN common stock at the election of the director.

<TABLE>
<CAPTION>

                         ALABAMA          GEORGIA         GULF      MISSISSIPPI        SAVANNAH

<S>                       <C>              <C>          <C>           <C>               <C>
Cash Retainer Fee         $17,000          $20,000      $10,000       $10,000           $10,000
Stock Retainer Fee         $3,000           $3,000       $2,000        $2,000            $2,000

Meeting Fee                   900              900          750           750               750

Committees:
     Audit                    900              900          750           750               750
     Compensation             900              900          750           750               750
     Executive                900              900            -             -               750
     Finance                    -              900            -           750                 -
     Nominating               900                -            -             -                 -
     Nuclear Safety           900                -            -             -                 -
     Nuclear Operations
       Overview                 -            1,800            -             -                 -
</TABLE>

         Effective January 1, 1997, the Outside Directors Pension Plan (the
"Plan") was terminated and benefits payable under the Plan were frozen.
Non-employee directors serving as of January 1, 1997, were given a one-time
election to receive a Plan benefit buy-out equal to the actuarial present value
of future Plan benefits or receive benefits under the terms of the Plan at the
annual retainer rate in effect on December 31, 1996. Directors who elected to
receive the benefit buy-out were required to defer receipt of that amount under
the Deferred Compensation Plan until termination from board membership.
Directors who elected to continue to participate under the terms of the Plan are
entitled to benefits upon retirement from the board on the retirement date
designated in the respective companies' by-laws. The annual benefit payable is
based upon length of service and varies from 75 percent of the annual retainer
in effect on December 31, 1996, if the participant has at least 60 months of
service on the board of one or more system companies, to 100 percent if the
participant has at least 120 months of such service. Payments will continue for
the greater of the lifetime of the participant or 10 years.

         Other Arrangements. No director received other compensation for
services as a director during the year ending December 31, 1999 in addition to
or in lieu of that specified by the standard arrangements specified above.

                                     III-28
<PAGE>


Employment Contracts and Termination of Employment and Change in Control
Arrangements.


Each registrant has adopted SOUTHERN's Change in Control Plan which is
applicable to certain of its officers, and has entered into individual change in
control agreements with its most highly compensated executive officers. If an
executive is involuntarily terminated, other than for cause, within two years
following a change in control of SOUTHERN the agreements provide for:

o lump sum payment of two or three times annual compensation, o up to five
years' coverage under group health and life insurance plans, o immediate vesting
of all stock options and stock appreciation rights 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
the agreement.

A 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.

     If a change in control affects only a subsidiary of SOUTHERN, these
payments would only be made to executives of the affected subsidiary who are
involuntarily terminated as a result of that change in control.

     SOUTHERN also has amended its short- and long-term incentive plans to
provide for pro-rata payments at not less than target-level performance if a
change in control occurs and the plans are not continued or replaced with
comparable plans.

     On February 28, 1998, SOUTHERN and GEORGIA entered into a Deferred
Compensation Agreement with Mr. Franklin. On the fifth anniversary of the
Agreement, if still employed by SOUTHERN or one of its subsidiaries, Mr.
Franklin will receive the cash value of the number of shares of common stock
that could have been purchased for $500,000 on February 28, 1998, and on which
dividends were reinvested throughout the five-year period. If certain
performance goals are met, Mr. Franklin also will receive the estimated income
tax expense on the compensation. Mr. Franklin may elect to defer receipt of the
award until termination of employment. GEORGIA assigned this agreement to SCS
effective July 8, 1999.

Report on Repricing of Options.

         None.

Compensation Committee Interlocks and Insider Participation.

         None.


                                     III-29
<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 registrants: ALABAMA, GEORGIA,
GULF, MISSISSIPPI and 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

                            Registrants:
                            ALABAMA                        5,608,955
                            GEORGIA                        7,761,500
                            GULF                             992,717
                            MISSISSIPPI                    1,121,000
                            SAVANNAH                      10,844,635

Security Ownership of Management. The following table shows the number of shares
of SOUTHERN common stock and operating  subsidiary  preferred stock owned by the
directors,  nominees and executive officers as of December 31, 1999. 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 of the respective
classes outstanding on December 31, 1999.

Name of Directors,
Nominees and                                       Number of Shares
Executive Officers          Title of Class         Beneficially Owned (1) (2)
------------------          --------------         --------------------------

ALABAMA

Whit Armstrong              SOUTHERN Common               17,972

David J. Cooper, Sr.        SOUTHERN Common                1,191

H. Allen Franklin           SOUTHERN Common              220,337

Elmer B. Harris             SOUTHERN Common              260,741

R. Kent Henslee             SOUTHERN Common                4,019

Carl E. Jones, Jr.          SOUTHERN Common               12,249

Patricia M. King            SOUTHERN Common                  306

James K. Lowder             SOUTHERN Common                6,241

                                     III-30
<PAGE>


Name of Directors,
Nominees and                                       Number of Shares
Executive Officers           Title of Class        Beneficially Owned (1) (2)
------------------           --------------       --------------------------

Wallace D. Malone, Jr.       SOUTHERN Common                627

Thomas C. Meredith           SOUTHERN Common                416

Mayer Mitchell               SOUTHERN Common                 19

William V. Muse              SOUTHERN Common                726

John T. Porter               SOUTHERN Common              1,181

Robert D. Powers             SOUTHERN Common                726

Andreas Renschler            SOUTHERN Common              1,223

C. Dowd Ritter               SOUTHERN Common                306

James H. Sanford             SOUTHERN Common                658

John C. Webb, IV             SOUTHERN Common             12,925

Banks H. Farris              SOUTHERN Common             43,485

Michael D. Garrett           SOUTHERN Common             18,216

William B. Hutchins, III     SOUTHERN Common             59,771

C. Alan Martin               SOUTHERN Common              5,320

Jerry L. Stewart             SOUTHERN Common             24,221

The directors, nominees,
and executive officers
as a group                   SOUTHERN Common            692,874


GEORGIA

Daniel P. Amos               SOUTHERN Common                297

Juanita P. Baranco           SOUTHERN Common                297

W. A. Fickling, Jr.          SOUTHERN Common              1,245




                               III-31

<PAGE>


Name of Directors,
Nominees and                                         Number of Shares
Executive Officers           Title of Class          Beneficially Owned (1) (2)
------------------           --------------          --------------------------

H. Allen Franklin            SOUTHERN Common                220,337

L. G. Hardman III            SOUTHERN Common                 17,422

James R. Lientz, Jr.         SOUTHERN Common                  1,271

Zell Miller                  SOUTHERN Common                    373

G. Joseph Prendergast        SOUTHERN Common                  1,331

Herman J. Russell            SOUTHERN Common                  2,962

W. J. Vereen                 SOUTHERN Common                  5,628

Carl Ware                    SOUTHERN Common                    800

William C. Archer, III       SOUTHERN Common                 27,794

Thomas A. Fanning            SOUTHERN Common                 23,726

Robert H. Haubein, Jr.       SOUTHERN Common                 40,381

Gene R. Hodges               SOUTHERN Common                 56,540

David M. Ratcliffe           SOUTHERN Common                 95,158

The directors, nominees
and executive officers
as a group                   SOUTHERN Common                629,177


GULF

Travis J. Bowden             SOUTHERN Common                 29,368

Fred C. Donovan, Sr.         SOUTHERN Common                    526

H. Allen Franklin            SOUTHERN Common                220,337

W. Deck Hull, Jr.            SOUTHERN Common                  3,164

Joseph K. Tannehill          SOUTHERN Common                  4,541


                                     III-32

<PAGE>
Name of Directors,
Nominees and                                        Number of Shares
Executive Officers           Title of Class         Beneficially Owned (1) (2)
------------------           --------------        --------------------------

Barbara H. Thames            SOUTHERN Common                    247

Francis M. Fisher, Jr.       SOUTHERN Common                 14,873

John E. Hodges, Jr.          SOUTHERN Common                 48,551

Robert G. Moore              SOUTHERN Common                 24,517

Arlan E. Scarbrough          SOUTHERN Common                 26,396


The directors, nominees
and executive officers
as a group                   SOUTHERN Common                372,520


MISSISSIPPI

Edwin E. Downer              SOUTHERN Common                  5,289

Dwight H. Evans              SOUTHERN Common                 79,309

Robert S. Gaddis             SOUTHERN Common                  2,143

Linda T. Howard              SOUTHERN Common                     66

Malcolm Portera              SOUTHERN Common                      59

George A. Schloegel          SOUTHERN Common                     589

Philip J. Terrell            SOUTHERN Common                     945

N. Eugene Warr               SOUTHERN Common                   1,081

H. E. Blakeslee              SOUTHERN Common                  36,328

Mark S. Lynch                SOUTHERN Common                      70

Don E. Mason                 SOUTHERN Common                  45,019

Michael W. Southern          SOUTHERN Common                  19,730

The directors, nominees
and executive officers
as a group                   SOUTHERN Common                 190,628


                                     III-33
<PAGE>
Name of Directors,
Nominees and                                          Number of Shares
Executive Officers           Title of Class           Beneficially Owned (1) (2)
------------------           --------------           --------------------------

SAVANNAH

Gus H. Bell, III             SOUTHERN Common                      38

Archie H. Davis              SOUTHERN Common                     275

Walter D. Gnann              SOUTHERN Common                   1,757

G. Edison Holland, Jr.       SOUTHERN Common                  43,065

Robert B. Miller, III        SOUTHERN Common                     536

Arnold M. Tenenbaum          SOUTHERN Common                     890

Lewis A. Jeffers             SOUTHERN Common                   7,923

W. Miles Greer               SOUTHERN Common                  15,900

Kirby R. Willis              SOUTHERN Common                  17,992


The directors, nominees
and executive officers
as a group                   SOUTHERN Common                  88,377



Changes in control.  SOUTHERN and the operating affiliates know of  no
arrangements which may at a subsequent date result in any change in control.

_______________________

(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, as follows:
     Mr. Blakeslee, 31,701 shares; Mr. Evans, 55,961 shares; Mr. Farris, 38,372
     shares; Mr. Franklin, 191,114 shares; Mr. Greer, 12,505 shares; Mr. Harris,
     219,394 shares; Mr. Haubein, 37,975 shares; Mr. G. R. Hodges, 38,577
     shares; Mr. J. E. Hodges, 24,796 shares; Mr. Holland, 40,342 shares; Mr.
     Hutchins, 43,701 shares; Mr. Mason, 20,994 shares; Mr. Southern, 15,139
     shares, and Mr. Willis, 11,770 shares.  Also included are shares of
     SOUTHERN common stock held by the spouses of the following directors:  Mr.
     Gaddis, 1,200 shares; Mr. Hardman, 100 shares; and Mr. Harris, 310 shares.
     Also included are shares of common stock held in the Southern Company
     Deferred Stock Trust of which certain directors have the power to direct
     the voting, as follows:  Mr. Hardman, 7,461 shares.



                               III-34

<PAGE>
Item 13.  CERTAIN RELATIONSHIPS AND
          RELATED TRANSACTIONS

             ALABAMA

Transactions with management and others.

     Mr. Whit Armstrong is President, Chairman and Chief Executive Officer of
The Citizens Bank, Enterprise, Alabama; Mr. Carl E. Jones, Jr. is President and
Chief Executive Officer of Regions Financial Corporation, Birmingham, Alabama;
Mr. Wallace D. Malone is Chairman and Chief Executive Officer of SouthTrust
Corporation, Birmingham, Alabama.  Mr. C. Dowd Ritter is Chairman, President
and Chief Executive Officer of AmSouth Bancorporation and AmSouth Bank,
Birmingham, Alabama.  During 1999, these banks furnished a number of regular
banking services in the ordinary course of business to ALABAMA.  ALABAMA intends
to maintain normal banking relations with all the aforesaid banks in the future.

Certain business relationships.
        None.

Indebtedness of management.
        None.

Transactions with promoters.
        None.

                    GEORGIA

Transactions with management and others.

     Mr. L. G. Hardman III is Chairman of the Board of The First National Bank
of Commerce, Georgia; Mr. James R. Lientz, Jr. is President of Bank of America
Mid-South Banking Group, Atlanta, Georgia; Mr. G. Joseph Prendergast is
President and Chief Operating Officer, Wachovia Corporation and Wachovia Bank,
N.A., Winston Salem, North Carolina, and Mr. Herman J. Russell is Chairman of
the Board of Citizens Trust Bank, Atlanta, Georgia.  During 1999, these banks
furnished a number of regular banking services in the ordinary course of
business to GEORGIA. GEORGIA intends to maintain normal banking relations with
all the aforesaid banks in the future.


     In 1999, GEORGIA leased a building from Riverside Manufacturing Co. for
$86,925.  Also, Riverside Manufacturing sold to GEORGIA fire retardant uniforms
for $134,464.  Mr. William J. Vereen is Chief Executive Officer, President,
Treasurer and Director of Riverside Manufacturing Co.

Certain business relationships.
        None.

Indebtedness of management.
        None.

Transactions with promoters.
        None.

              GULF

Transactions with management and others.

     In 1999, GULF paid to Merrick Industries, Inc. and Merrick Environmental
Technology, Inc., $560,712 for coal handling equipment and air pollution control
equipment.  Mr. Tannehill is Chairman and Chief Executive Officer of both
companies.


Certain business relationships.
        None.

Indebtedness of management.
        None.

Transactions with promoters.
        None.

              MISSISSIPPI

Transactions with management and others.

     Mr. Robert S. Gaddis is Chairman of the Advisory Board of Trustmark
National Bank, Laurel, Mississippi; Mr. George A. Schloegel is President of
Hancock Bank, Gulfport, Mississippi.  During 1999, these banks furnished a
number of regular banking services in the ordinary course of business to
MISSISSIPPI.  MISSISSIPPI intends to maintain normal banking relations with the
aforesaid banks in the future.

Certain business relationships.
        None.

Indebtedness of management.
        None.

Transactions with promoters.
        None.

                                     III-35
<PAGE>



                    SAVANNAH

Transactions with management and others.

     Mr. Archie Davis is President of The Savannah Bank,  N.A., Savannah,
Georgia;  During 1999, 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-36



<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-11 through IV-16.

         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 1999 were as follows:


     None.

                                      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:   A. W. Dahlberg, Chairman and
           Chief Executive Officer

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

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.

     A. W. Dahlberg
     Chairman of the Board and
     Chief Executive Officer
     (Principal Executive Officer)

     W. L. Westbrook
     Financial Vice President, Chief Financial Officer and
     Treasurer
     (Principal Financial and Accounting Officer)

                          Directors:
    Dorrit J. Bern                Elmer B. Harris
    Thomas F. Chapman             Donald M. James
    A. D. Correll                 David J. Lesar
    H. Allen Franklin             Zack T. Pate
    L. G. Hardman III             Gerald J. St. Pe'


     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     ALABAMA POWER COMPANY

     By:   Elmer B. Harris, President and
           Chief Executive Officer

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     Elmer B. Harris
     President, Chief Executive Officer and Director
     (Principal Executive Officer)

     William B. Hutchins, III
     Executive Vice President, Chief Financial Officer and Treasurer
     (Principal Financial Officer)

     Art P. Beattie
     Vice President, and Comptroller
     (Principal Accounting Officer)

                          Directors:
    Whit Armstrong                     Thomas C. Meredith
    David J. Cooper                    Mayer Mitchell
    H. Allen Franklin                  William V. Muse
    R. Kent Henslee                    John T. Porter
    Carl E. Jones, Jr.                 Robert D. Powers
    Patricia M. King                   C. Dowd Ritter
    James K. Lowder                    James H. Sanford
    Wallace D. Malone, Jr.             John Cox Webb, IV


     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

                                      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 24, 2000

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     David M. Ratcliffe
     President, Chief Executive Officer and Director
     (Principal Executive Officer)

     Thomas A. Fanning
     Executive Vice President, Chief Financial Officer
     and Treasurer
     (Principal Financial Officer)

     Cliff S. Thrasher
     Vice President, Comptroller and Chief Accounting Officer
     (Principal Accounting Officer)

                          Directors:
     Daniel P. Amos               Zell Miller
     Juanita P. Baranco           G. Joseph Prendergast
     William A. Fickling, Jr.     Herman J. Russell
     H. Allen Franklin            William Jerry Vereen
     L. G. Hardman III            Carl Ware
     James R. Lientz, Jr.


     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     GULF POWER COMPANY

     By:   Travis J. Bowden, President and
           Chief Executive Officer

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

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)

     Arlan E. Scarbrough
     Vice President - Finance
     (Principal Financial and Accounting Officer)

                        Directors:
     Fred C. Donovan, Sr.       Joseph K. Tannehill
     H. Allen Franklin          Barbara H. Thames
     W. Deck Hull, Jr.

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

                                      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:   Dwight H. Evans, President and
           Chief Executive Officer

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     Dwight H. Evans
     President, Chief Executive Officer and Director
     (Principal Executive Officer)

     Michael W. Southern
     Vice President, Secretary, Treasurer and
     Chief Financial Officer
     (Principal Financial and Accounting Officer)

                         Directors:
      Edwin E. Downer           Malcolm Portera
      Robert S. Gaddis          George A. Schloegel
      Linda T. Howard           Philip J. Terrell
      Aubrey K. Lucas           Gene Warr

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     SAVANNAH ELECTRIC AND POWER COMPANY

     By:   G. Edison Holland, Jr., President and
           Chief Executive Officer

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

      G. Edison Holland, Jr.
      President, Chief Executive Officer and Director
      (Principal Executive Officer)

      Kirby R. Willis
      Vice President, Treasurer and
      Chief Financial Officer
      (Principal Financial and Accounting Officer)

                        Directors:
     Gus H. Bell, III         Robert B. Miller, III
     Archie H. Davis          Arnold M. Tenenbaum
     Walter D. Gnann


     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 24, 2000

                                      IV-4

<PAGE>
                                 Arthur Andersen LLP



                                                              Exhibit 23(a)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





      As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 on the financial statements of The
Southern Company and its subsidiaries and the related financial statement
schedule, included in this Form 10-K, into The Southern Company's previously
filed Registration Statement File Nos. 2-78617, 33-3546, 33-30171, 33-51433,
33-54415, 33-57951, 33-58371, 33-60427, 333-09077, 333-44127, 333-44261,
333-64871 and 333-31808.





/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 2000




                                      IV-5
<PAGE>
                                 Arthur Andersen LLP

                                                             Exhibit 23(b)




                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





      As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 on the financial statements of Alabama
Power Company and the related financial statement schedule, included in this
Form 10-K, into Alabama Power Company's previously filed Registration Statement
File No. 333-67453.




/s/  Arthur Andersen LLP
Birmingham, Alabama
March 22, 2000




                                      IV-6

<PAGE>

                                 Arthur Andersen LLP


                                                               Exhibit 23(c)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





      As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 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. 333-43895 and 333-75193.





/s/  Arthur Andersen LLP
Atlanta, Georgia
March 22, 2000



                                      IV-7

<PAGE>

                                 Arthur Andersen LLP

                                                              Exhibit 23(d)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





      As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 on the financial statements of Gulf Power
Company and the related financial statement schedule, included in this Form
10-K, into Gulf Power Company's previously filed Registration Statement File
Nos. 33-50165 and 333-42033.




/s/  Arthur Andersen LLP
Atlanta, Georgia
March 22, 2000





                                      IV-8
<PAGE>


                                 Arthur Andersen LLP

                                                                Exhibit 23(e)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





     As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 on the financial statements of
Mississippi Power Company and the related financial statement schedule, included
in this Form 10-K, into Mississippi Power Company's previously filed
Registration Statement File No. 333-45069.





/s/  Arthur Andersen LLP
Atlanta, Georgia
March 22, 2000

                                      IV-9
<PAGE>

                                 Arthur Andersen LLP

                                                              Exhibit 23(f)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





      As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 on the financial statements of Savannah
Electric and Power Company and the related financial statement schedule,
included in this Form 10-K, into Savannah Electric and Power Company's
previously filed Registration Statement File No. 333-46171.




/s/  Arthur Andersen LLP
Atlanta, Georgia
March 22, 2000


                                     IV-10
<PAGE>

                                 Arthur Andersen LLP


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To The Southern Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the consolidated financial statements of The Southern Company
and its subsidiaries included in this Form 10-K, and have issued our report
thereon dated February 16, 2000. 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 16, 2000

                                     IV-11
<PAGE>

                                 Arthur Andersen LLP


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Alabama Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Alabama Power Company included in
this Form 10-K, and have issued our report thereon dated February 16, 2000. 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 16, 2000

                                     IV-12
<PAGE>

                                 Arthur Andersen LLP


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Georgia Power Company:

      We have audited in accordance with auditing standards generally accepted
in the United States, the financial statements of Georgia Power Company included
in this Form 10-K, and have issued our report thereon dated February 16, 2000.
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 16, 2000

                                     IV-13
<PAGE>

                                 Arthur Andersen LLP


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Gulf Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Gulf Power Company included in
this Form 10-K, and have issued our report thereon dated February 16, 2000. 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 16, 2000
                                     IV-14

<PAGE>

                                 Arthur Andersen LLP


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Mississippi Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Mississippi Power Company
included in this Form 10-K, and have issued our report thereon dated February
16, 2000. 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 16, 2000

                                     IV-15
<PAGE>

                                 Arthur Andersen LLP


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Savannah Electric and Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Savannah Electric and Power
Company included in this Form 10-K, and have issued our report thereon dated
February 16, 2000. 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 16, 2000


                                     IV-16

<PAGE>
                                       INDEX TO FINANCIAL STATEMENT SCHEDULES
<TABLE>
<CAPTION>

Schedule                                                                                                          Page

<S>                                                                                                                <C>
II     Valuation and Qualifying Accounts and Reserves
        1999, 1998 and 1997
         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.
</TABLE>





                                      S-1
<PAGE>
<TABLE>
<CAPTION>



                  THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
              FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
                        (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
  ------------------------------------- ------------------------ -------------- ------------------- --------------- ----------------
<S>                                            <C>                 <C>            <C>                 <C>                <C>
  Provision for uncollectible
     accounts
       1999..........................          $112,511            $55,042         $(11,805)          $96,838 (1)        $ 58,910
       1998..........................            77,056             64,789             6,325           35,659 (1)         112,511
       1997..........................            31,587             35,930            36,290 (2)       26,751 (1)          77,056

-------------------
</TABLE>
Notes:
    (1) Represents write-off of accounts considered to be uncollectible, less
    recoveries of amounts previously written off. (2) Includes the addition of a
    Purchased Reserve in the amount of $37,000 related to the acquisition of
    CEPA.

                                      S-2
<PAGE>
<TABLE>
<CAPTION>



                              ALABAMA POWER COMPANY
                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
              FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
                        (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
  ------------------------------------ ------------------------------------- ------------------ ----------------- ---------------
  <S>                                         <C>               <C>                <C>           <C>                <C>
Provision for uncollectible
    accounts
       1999..........................         $1,855            $13,995             $-            $11,733 (Note)        $4,117
       1998..........................          2,272              7,702              -              8,119 (Note)         1,855
       1997..........................          1,171              8,580              -              7,479 (Note)         2,272

-------------------
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, 1999, 1998 AND 1997
                        (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
  ----------------------------------- ----------------------- -------------- ------------------ ----------------- ----------------
  <S>                                         <C>               <C>            <C>                 <C>                <C>
  Provision for uncollectible
    accounts
       1999..........................         $5,500            $14,406             $-             $12,906 (Note)        $7,000
       1998..........................          3,000             17,856              -              15,356 (Note)         5,500
       1997..........................          4,000              7,888              -               8,888 (Note)         3,000


-------------------
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, 1999, 1998 AND 1997
                        (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
  ------------------------------------ ------------------------ --------------- ------------------ ---------------- ---------------
  <S>                                           <C>                <C>                  <C>         <C>                 <C>
  Provision for uncollectible
    accounts
       1999..........................           $996               $2,230               $-           $2,200 (Note)      $1,026
       1998..........................            796                2,288                -            2,088 (Note)         996
       1997..........................            789                1,350                -            1,343 (Note)         796

-------------------
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, 1999, 1998 AND 1997
                        (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
  ------------------------------------ ------------------------- -------------- ------------------ ---------------- ---------------
  <S>                                           <C>                <C>                <C>            <C>                  <C>
  Provision for uncollectible
    accounts
       1999..........................           $621                $1,964            $  -           $1,888 (Note)        $697
       1998..........................            698                 1,510              31            1,618 (Note)         621
       1997..........................            839                 1,128              56            1,325 (Note)         698

-------------------
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, 1999, 1998 AND 1997
                        (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
  -------------------------------------- ---------------------- ------------ ------------------ --------------- -----------------
  <S>                                             <C>                <C>            <C>           <C>                 <C>
  Provision for uncollectible
    accounts
       1999..........................             $284               $594           $-            $641 (Note)         $237
       1998..........................              354                417            -             487 (Note)          284
       1997..........................              632                192            -             470 (Note)          354

-------------------
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, respectively, as the exhibits and in the file numbers indicated and are
incorporated herein by reference. The exhibits marked with a pound sign are
management contracts or compensatory plans or arrangements required to be filed
herewith and required to be identified as such by Item 14 of Form 10-K.
Reference is made to a duplicate list of exhibits being filed as a part of this
Form 10-K, which list, prepared in accordance with Item 601 of Regulation S-K of
the SEC, immediately precedes the exhibits being physically filed with this Form
10-K.

(1)      Underwriting Agreements

         GEORGIA


           (c)           - Distribution Agreement dated November 29, 1995
                         between GEORGIA and Lehman Brothers Inc.; Donaldson,
                         Lufkin & Jenrette Securities Corporation; J. P. Morgan
                         Securities Inc.; Salomon Brothers Inc and Smith Barney
                         Inc. relating to $300,000,000 First Mortgage Bonds
                         Secured Medium-Term Notes. (Designated in GEORGIA's
                         Form 10-K for the year ended December 31, 1995, as
                         Exhibit 1(c).)


(3)      Articles of Incorporation and By-Laws

         SOUTHERN

           (a)  1   -    Composite Certificate of Incorporation of SOUTHERN,
                         reflecting all amendments thereto through January 5,
                         1994.  (Designated in Registration No. 33-3546 as
                         Exhibit 4(a), in Certificate of Notification, File No.
                         70-7341, as Exhibit A and in Certificate of
                         Notification, File No. 70-8181, as Exhibit A.)

           (a)  2   -    By-laws of SOUTHERN as amended effective October 21,
                         1991, and as presently in effect.  (Designated in Form
                         U-1, File No. 70-8181, as Exhibit A-2.)


         ALABAMA

           (b)  1   -    Charter of ALABAMA and amendments thereto through
                         August 10, 1998.  (Designated in Registration Nos.
                         2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c),
                         2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2,
                         2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2,
                         33-43917 as Exhibit 4(a)-2, in Form 8-K dated
                         February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3,
                         in Form 8-K dated July 8, 1992, File No. 1-3164, as
                         Exhibit 4(b)-3, in Form 8-K dated October 27, 1993,
                         File No. 1-3164, as Exhibits 4(a) and 4(b), in Form
                         8-K dated November 16, 1993, File No. 1-3164, as
                         Exhibit 4(a), in Certificate of Notification, File
                         No. 70-8191, as Exhibit A, in ALABAMA's Form 10-K for
                         the year ended December 31, 1997, File No. 1-3164, as
                         Exhibit 3(b)2 and Form 8-K dated August 10, 1998,
                         File No. 1-3164, as Exhibit 4.4.)

                                      E-1

<PAGE>

           (b)  2   -    By-laws of ALABAMA as amended effective July 23, 1993,
                         and as presently in effect.  (Designated in Form U-1,
                         File No. 70-8191, as Exhibit A-2.)


         GEORGIA

           (c)  1   -    Charter of GEORGIA and amendments thereto through
                         January 26, 1998.  (Designated in Registration Nos.
                         2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits
                         4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2),
                         2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit 4(a)-(2),
                         33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2),
                         33-14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504
                         as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in
                         GEORGIA's Form 10-K for the year ended December 31,
                         1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3),
                         in Registration No. 33-48895 as Exhibits 4(b)-(2) and
                         4(b)-(3), in Form 8-K dated December 10, 1992,
                         File No. 1-6468 as Exhibit 4(b), in Form 8-K dated
                         June 17, 1993, File No. 1-6468, as Exhibit 4(b), in
                         Form 8-K dated October 20, 1993, File No. 1-6468, as
                         Exhibit 4(b) and in GEORGIA's Form 10-K for the year
                         ended December 31, 1997, File No. 1-6468, as
                         Exhibit 3(c)2.)

           (c) 2 -       By-laws of GEORGIA as amended effective July 18,
                         1990, and as presently in effect. (Designated in
                         GEORGIA's Form 10-K for the year ended December 31,
                         1990, File No. 1-6468, as Exhibit 3.)


         GULF

          (d) 1 -        Restated  Articles  of  Incorporation  of GULF and
                         amendments  thereto through January 28, 1998.
                         (Designated in  Registration  No. 33-43739 as Exhibit
                         4(b)-1, in Form 8-K dated January 15, 1992, File No.
                         0-2429, as Exhibit 1(b), in Form 8-K dated August 18,
                         1992, File No. 0-2429,  as Exhibit 4(b)-2, in Form 8-K
                         dated  September  22,  1993,  File No.  0-2429,  as
                         Exhibit 4, in Form 8-K dated November 3, 1993, File
                         No. 0-2429,  as Exhibit 4 and in GULF's Form 10-K for
                         the year ended December 31, 1997, File No. 0-2429, as
                         Exhibit 3(d)2.)

           (d)  2   -    By-laws of GULF as amended effective July 26, 1996,
                         and as presently in effect.  (Designated in Form U-1,
                         File No. 70-8949, as Exhibit A-2(c).)


         MISSISSIPPI

           (e)  1   -    Articles of Incorporation of MISSISSIPPI, articles of
                         merger of Mississippi Power Company (a Maine
                         corporation) into MISSISSIPPI and articles of
                         amendment to the articles of incorporation of
                         MISSISSIPPI through December 31, 1997. (Designated in
                         Registration No. 2-71540 as Exhibit 4(a)-1, in Form
                         U5S for 1987, File No. 30-222-2, as Exhibit B-10, in
                         Registration No. 33-49320 as Exhibit 4(b)-(1), in Form
                         8-K dated August 5, 1992, File No. 0-6849, as
                         Exhibits 4(b)-2 and 4(b)-3, in Form 8-K dated August
                         4, 1993, File No. 0-6849, as Exhibit 4(b)-3, in Form
                         8-K dated August 18, 1993, File No. 0-6849, as
                         Exhibit 4(b)-3 and in MISSISSIPPI's Form 10-K for the
                         year ended December 31, 1997, File No. 0-6849, as
                         Exhibit 3(e)2.)

                                      E-2

<PAGE>

           (e)  2   -    By-laws of MISSISSIPPI as amended effective April 2,
                         1996, and as presently in effect.  (Designated in Form
                         U5S for 1995, File No. 30-222-2, as Exhibit B-10.)


         SAVANNAH

           (f)  1   -    Charter of SAVANNAH and amendments thereto through
                         December 2, 1998.  (Designated in Registration Nos.
                         33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4
                         (b)-(2), in Form 8-K dated November 9, 1993, File No.
                         1-5072, as Exhibit 4(b) and in SAVANNAH's Form 10-K
                         for the year ended December 31, 1998, as
                         Exhibit 3(f)2.)

           (f)  2   -    By-laws of SAVANNAH as amended effective February 16,
                         1994, and as presently in effect.  (Designated in
                         SAVANNAH's Form 10-K for the year ended December 31,
                         1993, 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 that dated as of December
                         23, 1998.  (Designated in SOUTHERN's Form 10-K for the
                         year ended December 31, 1997, File No. 1-3526, as
                         Exhibit (4)(a)2, in Form 8-K dated June 18, 1998, File
                         No. 1-3526, as Exhibit 4.2 and in Form 8-K dated
                         December 18, 1998, File No. 1-3526, as Exhibit 4.4.)

           (a)  3   -    Amended and Restated Trust Agreement of Southern
                         Company Capital Trust I dated as of February 1, 1997.
                         (Designated in Registration No. 333-28349 as
                         Exhibit 4.6)

           (a)  4   -    Amended and Restated Trust Agreement of Southern
                         Company Capital Trust II dated as of February 1, 1997.
                         (Designated in Registration No. 333-28355 as
                         Exhibit 4.6)

           (a)  5   -    Amended and Restated Trust Agreement of Southern
                         Company Capital Trust III dated as of June 1, 1997.
                         (Designated in SOUTHERN's Form 10-K for the year ended
                         December 31, 1997, File No. 1-3526, as Exhibit
                         (4)(a)5.)

           (a)  6   -    Amended and Restated Trust Agreement of Southern
                         Company Capital Trust IV dated as of June 1, 1998.
                         (Designated in Form 8-K dated June 18, 1998, File No.
                         1-3526, as Exhibit 4.5.)


                                      E-3

<PAGE>

           (a)  7   -    Amended and Restated Trust Agreement of Southern
                         Company Capital Trust V dated as of December 1, 1998.
                         (Designated in Form 8-K dated December 18, 1998, File
                         No. 1-3526, as Exhibit 4.7A.)

           (a)  8   -    Capital Securities Guarantee Agreement relating to
                         Southern Company Capital Trust I dated as of
                         February 1, 1997. (Designated in Registration No.
                         333-28349 as Exhibit 4.10)

           (a)  9   -    Capital Securities Guarantee Agreement relating to
                         Southern Company Capital Trust II dated as of
                         February 1, 1997. (Designated in Registration No.
                         333-28355 as Exhibit 4.10)

           (a)  10  -    Preferred Securities Guarantee Agreement relating to
                         Southern Company Capital Trust III dated as of June 1,
                         1997.  (Designated in SOUTHERN's Form 10-K for the
                         year ended December 31, 1997, File No. 1-3526, as
                         Exhibit (4)(a)8.)

           (a)  11  -    Preferred Securities Guarantee Agreement relating to
                         Southern Company Capital Trust IV dated as of June 1,
                         1998.  (Designated in Form 8-K dated June 18, 1998,
                         File No. 1-3626, as Exhibit 4.8.)

           (a)  12  -    Preferred Securities Guarantee Agreement relating to
                         Southern Company Capital Trust V dated as of
                         December 1, 1998.  (Designated in Form 8-K dated
                         December 18, 1998, File No. 1-3526, as Exhibit 4.11A.)


         ALABAMA

           (b)  1   -    Indenture dated as of January 1, 1942, between ALABAMA
                         and The Chase Manhattan Bank (formerly Chemical Bank),
                         as Trustee, and indentures supplemental thereto
                         through that dated as of December 1, 1994.
                         (Designated in Registration Nos. 2-59843 as Exhibit
                         2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716
                         as Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as
                         Exhibit 2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as
                         Exhibit 4(a)-2, 2-73727 as Exhibit 4(a)-2, 33-5079 as
                         Exhibit 4(a)-2, 33-17083 as Exhibit 4(a)-2, 33-22090
                         as Exhibit 4(a)-2, in ALABAMA's Form 10-K for the year
                         ended December 31, 1990, File No. 1-3164, as
                         Exhibit 4(c), in Registration Nos. 33-43917 as
                         Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885
                         as Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in
                         Form 8-K dated January 20, 1993, File No. 1-3164, as
                         Exhibit 4(a)-3, in Form 8-K dated February 17, 1993,
                         File No. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated
                         March 10, 1993, File No. 1-3164, as Exhibit 4(a)-3, in
                         Certificate of Notification, File No. 70-8069, as
                         Exhibits A and B, in Form 8-K dated June 24, 1993,
                         File No. 1-3164, as Exhibit 4, in Certificate of
                         Notification, File No. 70-8069, as Exhibit A, in
                         Form 8-K dated November 16, 1993, File No. 1-3164, as
                         Exhibit 4(b), in Certificate of Notification,
                         File No. 70-8069, as Exhibits A and B, in Certificate
                         of Notification, File No. 70-8069, as Exhibit A, in
                         Certificate of Notification, File No. 70-8069, as
                         Exhibit A and in Form 8-K dated November 30,
                         1994, File No. 1-3164, as Exhibit 4.)

           (b)  2   -    Subordinated Note Indenture dated as of January 1,
                         1996, between ALABAMA and The Chase Manhattan Bank
                         (formerly Chemical Bank), as Trustee, and indenture
                         supplemental thereto dated as of January 1, 1996.
                         (Designated in Certificate of Notification, File No.
                         70-8461, as Exhibits E and F.)



                                      E-4
<PAGE>
<TABLE>

<CAPTION>

<S>        <C>           <C>
           (b)  3   -    Subordinated Note Indenture dated as of January 1, 1997, between ALABAMA and The Chase Manhattan Bank, as
                         Trustee, and indentures supplemental thereto through that dated as of February 25, 1999.  (Designated in
                         Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2 and in Form 8-K dated
                         February 18, 1999, File No. 3164, as Exhibit 4.2.)

         (b)  4 -        Senior Note Indenture dated as of December 1, 1997,
                         between  ALABAMA  and  The  Chase  Manhattan  Bank,  as
                         Trustee,  and indentures  supplemental  thereto through
                         that dated September 30, 1999.  (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
                         and in Form 8-K  dated  September  21,  1999,  File No.
                         1-3164, as Exhibit 4.2.)

           (b)  5   -    Amended and  Restated  Trust  Agreement  of Alabama
                         Power  Capital  Trust I dated as of  January  1,  1996.
                         (Designated in Certificate  of  Notification,  File No.
                         70-8461, as Exhibit D.)

           (b) 6   -     Amended  and  Restated  Trust  Agreement  of Alabama
                         Power  Capital  Trust  II  dated  as  of  January  1,  1997.
                        (Designated  in Form 8-K dated  January  9,  1997,  File No.
                        1-3164, as Exhibit 4.5.)

           (b)  7   -    Amended and Restated Trust Agreement of Alabama Power Capital Trust III dated as of February 1, 1999.
                         (Designated in Form 8-K dated February 18, 1999, File No. 1-3164, as Exhibit 4.5.)

           (b)  8   -    Guarantee Agreement relating to Alabama Power Capital Trust I dated as of January 1, 1996.  (Designated in
                         Certificate of Notification, File No. 70-8461, as Exhibit G.)

           (b)  9   -    Guarantee Agreement relating to Alabama Power Capital Trust II dated as of January 1, 1997. (Designated in
                         Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibit 4.8.)

           (b)  10  -    Guarantee Agreement relating to Alabama Power Capital Trust III dated as of February 1, 1999.
                         (Designated in  Form 8-K dated February 18, 1999, File No. 1-3164, as Exhibit 4.8.)


         GEORGIA

           (c)  1   -    Indenture dated as of March 1, 1941, between
                         GEORGIA and The Chase Manhattan Bank (formerly Chemical
                         Bank), as Trustee, and indentures supplemental thereto
                         dated as of March 1, 1941, March 3, 1941 (3
                         indentures),


                                      E-5

<PAGE>

                         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   -    Indenture dated as of December 1, 1994, between GEORGIA and Trust Company Bank, as Trustee and indentures
                         supplemental thereto through that dated as of December 15, 1994.  (Designated in Certificate of
                         Notification, File No. 70-8461, as Exhibits E and F.)

           (c)  3   -    Subordinated Note Indenture dated as of August 1, 1996, between GEORGIA and The Chase Manhattan Bank, as
                         Trustee, and indentures supplemental thereto through January 1, 1997.  (Designated in Form 8-K dated August
                         21, 1996, File No. 1-6468, as Exhibits 4.1 and 4.2 and in Form 8-K dated January 9, 1997, File No. 1-6468,
                         as Exhibit 4.2.)

           (c)  4   -    Subordinated Note Indenture dated as of June 1, 1997, between GEORGIA and The Chase Manhattan Bank, as
                         Trustee, and indentures supplemental thereto through that dated as of February 25, 1999.  (Designated in
                         Certificate of Notification, File No. 70-8461, as Exhibits D and E and Form 8-K dated February 17, 1999,
                         File No. 1-6468, as Exhibit 4.4.)

                                      E-6

<PAGE>


           (c)  5   -    Senior Note Indenture dated as of January 1, 1998, between GEORGIA and The Chase Manhattan Bank, as
                         Trustee, and indentures supplemental thereto through that dated as of February 22, 2000.  (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 and in Form 8-K dated February 15, 2000, File No. 1-6469 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.)

      GULF

           (d)  1   -    Indenture dated as of September 1, 1941, between GULF and The Chase Manhattan Bank (formerly The Chase
                         Manhattan Bank (National Association)), as Trustee, and indentures supplemental thereto through
                         November 1, 1996.(Designated in Registration Nos. 2-4833 as Exhibit B-3, 2-62319 as Exhibit 2(a)-3,
                         2-63765 as Exhibit 2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2, 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.)

                                      E-7

           (d)  2   -    Subordinated Note Indenture dated as of January 1, 1997, between GULF and The Chase Manhattan Bank, as
                         Trustee, and indentures supplemental thereto through that dated as of January 1, 1998.  (Designated in Form
                         8-K dated January 27, 1997, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated July 28, 1997, File
                         No. 0-2429, as Exhibit 4.2 and in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.2.)

           (d)  3   -    Senior Note Indenture dated as of January 1, 1998, between GULF and The Chase Manhattan Bank, as Trustee,
                         and indenture supplemental thereto dated as of August 24, 1999.  (Designated in Form 8-K dated June 17,
                         1998, File No. 0-2429, as Exhibits 4.1 and 4.2 and in Form 8-K dated August 17, 1999, File No. 0-2429, as
                         Exhibit 4.2.)

           (d)  4   -    Amended and Restated Trust Agreement of Gulf Power Capital Trust I dated as of January 1, 1997.(Designated
                         in Form 8-K dated January 27, 1997, File No. 0-2429, as Exhibit 4.5.)

           (d)  5   -    Amended and Restated Trust Agreement of Gulf Power Capital Trust II dated as of January 1, 1998.(Designated
                         in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.5.)

           (d)  6   -    Guarantee Agreement relating to Gulf Power Capital Trust I dated as of January 1, 1997.(Designated in Form
                         8-K dated January 27, 1997, File No. 0-2429, as Exhibit 4.8.)

           (d)  7   -    Guarantee Agreement relating to Gulf Power Capital Trust II dated as of January 1, 1998.(Designated in Form
                         8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.8.)


         MISSISSIPPI

           (e)  1   -    Indenture dated as of September 1, 1941, between MISSISSIPPI and Bankers Trust Company, as Successor
                         Trustee, and indentures supplemental thereto through December 1, 1995.  (Designated in Registration Nos.
                         2-4834 as Exhibit B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2, 2-71537 as Exhibit 4(a)-(2),
                         33-5414 as Exhibit 4(a)-(2), 33-39833 as Exhibit 4(a)-2, in MISSISSIPPI's Form 10-K for the year ended
                         December 31, 1991, File No. 0-6849, as Exhibit 4(b), in Form 8-K dated August 5, 1992, File No. 0-6849,
                         as Exhibit 4(a)-2, in Second Certificate of Notification, File No. 70-7941, as Exhibit I, in MISSISSIPPI's
                         Form 8-K dated February 26, 1993, File No. 0-6849, as Exhibit 4(a)-2, in Certificate of Notification,
                         File No. 70-8127, as Exhibit A, in Form 8-K dated June 22, 1993, File No. 0-6849, as Exhibit 1, in
                         Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated March 8, 1994, File No.
                         0-6849, as Exhibit 4, in Certificate of Notification, File No. 70-8127, as Exhibit C and in Form 8-K dated
                         December 5, 1995, File No.  0-6849, as Exhibit 4.)


                                      E-8
<PAGE>

           (e)  2   -    Senior Note Indenture dated as of May 1, 1998 between MISSISSIPPI and Bankers Trust Company, as Trustee and
                         indentures supplemental thereto through May 20, 1998. (Designated in Form 8-K dated May 14, 1998, File No.
                         0-6849, as Exhibits 4.1, 4.2(a) and 4.2(b).)

           (e)  3   -    Subordinated Note Indenture dated as of February 1, 1997, between MISSISSIPPI and Bankers Trust Company, as
                         Trustee, and indenture supplemental thereto dated as of February 1, 1997.  (Designated in Form 8-K dated
                         February 20, 1997, File No. 0-6849, as Exhibits 4.1 and 4.2.)

           (e)  4   -    Amended and Restated Trust Agreement of Mississippi Power Capital Trust I dated as of February 1, 1997.
                         (Designated in Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibit 4.5.)

           (e)  5   -    Guarantee Agreement relating to Mississippi Power Capital Trust I dated as of February 1, 1997.(Designated
                         in Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibit 4.8.)


         SAVANNAH

           (f)  1   -    Indenture dated as of March 1, 1945, between SAVANNAH and The Bank of New York, New York, as Trustee, and
                         indentures supplemental thereto through May 1, 1996.  (Designated in Registration Nos. 33-25183 as Exhibit
                         4(a)-(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit 4(a)-(2), in SAVANNAH's Form 10-K for the year
                         ended December 31, 1991, File No. 1-5072, as Exhibit 4(b), in Form 8-K dated July 8, 1992, File No. 1-5072,
                         as Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit 4(a)-(2), in Form 8-K dated July 22, 1993, File
                         No. 1-5072, as Exhibit 4, in Form 8-K dated May 18, 1995, File No. 1-5072, as Exhibit 4 and in Form 8-K
                         dated May 23, 1996, File No. 1-5072, as Exhibit 4.)

           (f)  2   -    Senior Note Indenture dated as of March 1, 1998 between SAVANNAH and The Bank of New York, as Trustee and
                         indenture supplemental thereto dated as of March 1, 1998.  (Designated in Form 8-K dated March 9, 1998,
                         File No. 1-5072, as Exhibits 4.1 and 4.2.)

           (f)  3   -    Subordinated Note Indenture dated as of December 1, 1998, between SAVANNAH and The Bank of New York, as
                         Trustee, and indenture supplemental thereto dated as of December 9, 1998.  (Designated in Form 8-K dated
                         December 3, 1998, File No. 1-5072, as Exhibit 4.3 and 4.4.)

           (f)  4   -    Amended and Restated Trust Agreement of Savannah Electric Capital Trust I dated as of December 1, 1998.
                         (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.7.)

           (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.)

                                      E-9

<PAGE>


(10)     Material Contracts

         SOUTHERN

           (a)  1   -    Service contracts dated as of January 1, 1984, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO
                         and SOUTHERN and Amendment No. 1 dated as of September 6, 1985 between SCS and SOUTHERN.  (Designated in
                         SOUTHERN's Form 10-K for the year ended December 31, 1984, File No. 1-3526, as Exhibit 10(a) and in
                         SOUTHERN's Form 10-K for the year ended December 31, 1985, File No. 1-3526, as Exhibit 10(a)(3).)

           (a)  2   -    Service contract dated as of July 17, 1981, between SCS and SEI.  (Designated in SOUTHERN's Form 10-K for
                         the year ended December 31, 1985, File No. 1-3526, as Exhibit 10(a)(2).)

           (a)  3   -    Service contract dated as of March 3, 1988, between SCS and SAVANNAH.  (Designated in SAVANNAH's Form 10-K
                         for the year ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.)

           (a)  4   -    Service contract dated as of January 15, 1991, between SCS and Southern Nuclear. (Designated in SOUTHERN's
                         Form 10-K for the year ended December 31, 1991, File No. 1-3526, as Exhibit 10(a)(4).)

           (a)  5   -    Service contract dated as of December 12, 1994, between SCS and Mobile Energy Services Company, Inc.
                         (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit
                         10(a)58.)

           (a)  6   -    Interchange contract dated October 28, 1988, effective January 1, 1989, between 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(b).)

           (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).)


                                      E-10
<PAGE>

           (a)  11  -    Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between
                         GEORGIA and OPC.  (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No.
                         1-6468, as Exhibit 10(g).)

           (a)  12  -    Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of March 26, 1976, between
                         GEORGIA and OPC.  (Designated in Certificate of Notification, File No. 70-5592, as Exhibit A.)

           (a)  13  -    Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between GEORGIA and OPC.  (Designated in
                         Certificate of Notification, File No. 70-5592, as Exhibit B.)

           (a)  14  -    Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of August 27, 1976,
                         between GEORGIA, MEAG and Dalton.  (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as
                         Exhibit (b)(1).)

           (a)  15  -    Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between GEORGIA, MEAG and
                         Dalton.  (Designated in Form 8-K for February 1977, File No. 1-6468, as Exhibit (b)(2).)

           (a)  16  -    Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of
                         August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among GEORGIA, OPC, MEAG and Dalton.
                         (Designated in Form U-1, File No. 70-5792, as Exhibit B-1 and in Form 8-K for January 1977,
                         File No. 1-6468, as Exhibit (B)(3).)

           (a)  17  -    Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among
                         GEORGIA, OPC, MEAG and Dalton.  (Designated in Form U-1, File No. 70-5792, as Exhibit B-2.)

           (a)  18  -    Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption Agreement
                         dated as of November 16, 1983, between GEORGIA and MEAG.  (Designated in GEORGIA's Form 10-K for the year
                         ended December 31, 1983, File No. 1-6468, as Exhibit 10(k)(4).)

           (a)  19  -    Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between
                         GEORGIA and MEAG.  (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(2).)

           (a)  20  -    Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG.(Designated in
                         Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(4).)

           (a)  21  -    Nuclear Operating Agreement between Southern
                         Nuclear and GEORGIA dated as of July 1, 1993.
                         (Designated in SOUTHERN's Form 10-K for the year ended
                         December 31, 1997, File No. 1-3526, as Exhibit
                         10(a)21.)

           (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.)


                                      E-11

<PAGE>

           (a)  23  -    Plant Hal Wansley Purchase and Ownership
                         Participation Agreement dated as of April 19, 1977,
                         between GEORGIA and Dalton. (Designated in Form 8-K
                         dated as of June 13, 1977, File No. 1-6468, as Exhibit
                         (b)(3).)

           (a)  24  -    Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between GEORGIA and Dalton.
                         (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(7).)

           (a)  25  -    Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of
                         May 15, 1980, Amendment No. 1 dated as of December 30, 1985, Amendment No. 2 dated as of July 1, 1986,
                         Amendment No. 3 dated as of August 1, 1988 and Amendment No. 4 dated as of December 31, 1990, among
                         GEORGIA, OPC, MEAG and Dalton.  (Designated in Form U-1, File No. 70-6481, as Exhibit B-3, in SOUTHERN's
                         Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(2), in SOUTHERN's Form
                         10-K for the year ended December 31, 1989, File No. 1-3526, as Exhibit 10(n)(2) and in SOUTHERN's Form
                         10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)54.)

           (a)  26  -    Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980, Amendment
                         No. 1 dated as of December 3, 1985 and Amendment No. 2 dated as of December 31, 1990, among GEORGIA, OPC,
                         MEAG and Dalton.  (Designated in Form U-1, File No. 70-6481, as Exhibit B-4, in SOUTHERN's Form 10-K for
                         the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(4) and in SOUTHERN's Form 10-K for the
                         year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)55.)

           (a)  27  -    Plant Robert W. Scherer Purchase, Sale and Option Agreement dated as of May 15, 1980, between GEORGIA and
                         MEAG.  (Designated in Form U-1, File No. 70-6481, as Exhibit B-1.)

           (a)  28  -    Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between GEORGIA and Dalton.
                         (Designated in Form U-1, File No. 70-6481, as Exhibit B-2.)

           (a)  29  -    Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of
                         March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988,
                         between GEORGIA and GULF.  (Designated in Form U-1, File No. 70-6573, as Exhibit B-4, in SOUTHERN's Form
                         10-K for the year ended December 31, 1987, as Exhibit 10(o)(2) and in SOUTHERN's Form 10-K for the year
                         ended December 31, 1989, as Exhibit 10(n)(2).)

           (a)  30  -    Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA
                         and GULF.  (Designated in Form U-1, File No. 70-6573, as Exhibit B-5.)

                                      E-12

<PAGE>


           (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  -    Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18,
                         1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. (Designated in MISSISSIPPI's Form 10-K
                         for the year ended December 31, 1981, File No. 0-6849, as Exhibit 10(c)(2) and in GEORGIA's Form 10-K for
                         the year ended December 31, 1982, File No. 1-6468, as Exhibit 10(r)(3).)

           (a)  34  -    Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1 dated August 30, 1984
                         and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS.
                         (Designated in GEORGIA's Form 10-K for the year ended December 31, 1982, File No. 1-6468, as Exhibit
                         10(s)(2), in SOUTHERN's Form 10-K for the year ended December 31, 1984, File No. 1-3526, as Exhibit 10(r)
                         (2) and in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(s)(2).)

           (a)  35  -    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)  36  -    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)  37  -    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)  38  -    Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990,
                         File No. 1-6468, as Exhibit 10(x).)


                                      E-13
<PAGE>


           (a)  39  -    Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  (Designated in GULF's Form 10-K for the year ended December 31, 1991, File No. 0-2429,
                         as Exhibit 10(1).)

           (a)  40  -    Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  (Designated in GULF's Form 10-K for the year ended December 31, 1991, File No. 0-2429,
                         as Exhibit 10(m).)

           (a)  41  -    Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18,
                         1988, between OPC and GEORGIA.  (Designated in GEORGIA's Form 10-K for the year ended December 31, 1988,
                         File No. 1-6468, as Exhibit 10(x).)

           (a)  42  -    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)  43  -    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)  44  -    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)  45  -    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)  46  -    Long Term Transaction Service Agreement between GEORGIA and OPC dated as of February 29, 1999.

           (a)  47  -    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)  48  -    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.)

                                      E-14
<PAGE>

           (a)  49  -    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)  50  -    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)  51  -    Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December
                         7, 1990.  (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as
                         Exhibit 10(hh).)

           (a)  52  -    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)  53  -    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)  54  -    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)  55  -    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)  56 -     Power Purchase Agreement dated as of December 3,
                         1993 between GEORGIA and FPC. (Designated in SOUTHERN's
                         Form 10-K for the year ended December 31, 1993, File
                         No. 1-3526, as Exhibit 10(a)59.)

           (a)  57  -    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)  58  -    The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998.
                         (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as
                         Exhibit 10(a)59.)

      #  * (a)  59  -    The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective
                         January 1, 1999.


                                      E-15
<PAGE>


           (a)  60  -    The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Three. (Designated in SOUTHERN's Form 10-K for the year ended
                         December 31, 1998, File No. 1-3526 as Exhibit 10(a)61.)

         * (a)  61  -    Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan.

           (a)  62  -    The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Two. (Designated in SOUTHERN's Form 10-K for the year ended
                         December 31, 1998, File No. 1-3526 as Exhibit 10(a)62.)

         * (a)  63  -    Amendment Number Three to The Southern Company Employee Stock Ownership Plan.

           (a)           64 - The Southern Company Performance Pay Plan, Amended
                         and Restated effective January 1, 1998. (Designated in
                         SOUTHERN's Form 10-K for the year ended December 31,
                         1998, File No. 1-3526 as Exhibit 10(a)63.)

      #  * (a)  65  -    The Deferred Compensation Plan for the Directors of The Southern Company, Amended and Restated effective
                         February 17, 1997.

      #    (a)  66  -    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)  67  -    The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998.
                         (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as
                         Exhibit 10(a)66.)

      #    (a)  68  -    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.)

      #    (a)  69  -    Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto.
                         (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1995, File No. 1-3526, as Exhibit
                         10(a)80.)

      #  * (a)  70  -    The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999.

           (a)  71  -    The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
                         Amendment Number Three.  (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 and in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as
                         Exhibit 10(a)71.)

         * (a)  72  -    Amendment Number Four to The Southern Company Pension Plan.

                                      E-16
<PAGE>

      #    (a)  73  -    The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999.  (Designated in
                         Registration No. 333-31808 as Exhibit 4(c).)

      #  * (a)  74  -    The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective
                         January 1, 1999.

      #    (a)  75  -    The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
                         Amendment Number Six.  (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No.
                         1-3526, as Exhibit 10(a)82 and in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No.
                         1-3526 as Exhibit 10(a)76.)

      #  * (a)  76  -    Amendment Number Seven to The Southern Company Performance Sharing Plan.

      #    (a)  77  -    The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998. (Designated
                         in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)77.)

      #  * (a)  78  -    Amendment Number One to The Southern Company Supplemental Benefit Plan.

           (a)  79  -    Southern Company Change in Control Severance Plan, effective December 7, 1998. (Designated in SOUTHERN's
                         Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)78.)

         * (a)  80  -    Amendment Number One to Southern Company Change in Control Severance Plan.

      #                  (a) 81 - Southern Company Executive Change in Control
                         Severance Plan, effective December 7, 1998. (Designated
                         in SOUTHERN's Form 10-K for the year ended December 31,
                         1998, File No. 1-3526 as Exhibit 10(a)79.)

      #  * (a)  82  -    Amendment Number One to Southern Company Executive Change in Control Severance Plan.

      #                  (a) 83 - Deferred Compensation Agreement between
                         SOUTHERN, GEORGIA and Henry Allen Franklin. (Designated
                         in SOUTHERN's Form 10-K for the year ended December 31,
                         1998, File No. 1-3526 as Exhibit 10(a)80.)

      #  * (a)  84  -    Amendment Number One and Assignment to SCS of Deferred Compensation Agreement between SOUTHERN, GEORGIA and
                         Henry Allen Franklin.

      #    (a)  85  -    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)  86  -    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)  87  -    Deferred Compensation Agreement between SOUTHERN, Southern Energy Resources, Inc. and Gale E. Klappa and
                         First Amendment and Assignment to SCS.

                                      E-17

<PAGE>

      #  * (a)  88  -    Deferred Compensation Agreement between SOUTHERN, Southern Energy Resources, Inc. and S. Marce Fuller.

      #    (a)  89  -    Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden. (Designated in SOUTHERN's Form
                         10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)84.)

      #    (a)  90  -    Change in Control Agreement between SOUTHERN, SCS and A. W. Dahlberg. (Designated in SOUTHERN's Form 10-K
                         for  the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)85.)

      #    (a)  91  -    Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans. (Designated in SOUTHERN's
                         Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)87.)

      #    (a)  92  -    Change in Control Agreement between SOUTHERN, ALABAMA and Banks Harry Farris. (Designated in SOUTHERN's
                         Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)88.)

      #  * (a)  93  -    Change in Control Agreement between SOUTHERN, SCS and Henry Allen Franklin.

      #    (a)  94  -    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, 1998, File No. 1-3526 as Exhibit 10(a)90.)

      #    (a)  95  -    Change in Control Agreement between SOUTHERN, ALABAMA and Elmer B. Harris. (Designated in SOUTHERN's Form
                         10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)91.)

      #    (a)  96  -    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, 1998, File No. 1-3526 as Exhibit 10(a)92.)

      #    (a)  97  -    Change in Control Agreement between SOUTHERN, SCS and C. Alan Martin. (Designated in SOUTHERN's Form 10-K
                         for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)93.)

      #    (a)  98  -    Change in Control Agreement between SOUTHERN, SCS and Charles Douglas McCrary. (Designated in SOUTHERN's
                         Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)94.)

      #    (a)  99  -    Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe. (Designated in SOUTHERN's
                         Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)95.)

      #    (a)  100 -    Change in Control Agreement between SOUTHERN, SCS and Stephen A. Wakefield. (Designated in SOUTHERN's Form
                         10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)96.)


                                      E-18

<PAGE>

      #    (a)  101 -    Change in Control Agreement between SOUTHERN, SCS and W. Lawrence Westbrook. (Designated in SOUTHERN's Form
                         10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)97.)

      #  * (a)  102 -    Change in Control Agreement between SOUTHERN, SCS and Gale E. Klappa.

      #  * (a)  103 -    Change in Control Agreement between SOUTHERN, Southern Energy Resources, Inc. and S. Marce Fuller and First
                         Amendment thereto.

      #  * (a)  104 -    Separation Agreement For Thomas G. Boren.


         ALABAMA

           (b)  1   -    Service contracts dated as of January 1, 1984, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO
                         and SOUTHERN and Amendment No. 1 dated as of September 6, 1985 between SCS and SOUTHERN.  See Exhibit
                         10(a)1  herein.

           (b)  2   -    Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH 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   -    Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18,
                         1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS.  See Exhibit 10(a)33 herein.

           (b)  5   -    Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1, dated August 30,
                         1984 and Amendment No. 2, dated October 30, 1987,  between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and
                         SCS. See Exhibit 10(a)34 herein.

           (b)  6   -    Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)35 herein.

           (b)  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)36 herein.

           (b)  8   -    Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)37 herein.

           (b)  9   -    Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)38 herein.


                                      E-19

<PAGE>

           (b)  10  -    Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)39 herein.

           (b)  11  -    Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.   See Exhibit 10(a)40 herein.

           (b)  12  -    Firm Power Purchase Contract between ALABAMA and AMEA.  (Designated in Certificate of Notification,
                         File No.  70-7212, as Exhibit B.)

           (b)  13  -    1991 Firm Power Purchase Contract between ALABAMA and AMEA.  (Designated in Form U-1, File No. 70-7873, as
                         Exhibit B-1.)

           (b)  14  -    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)43
                         herein.

           (b)  15 -     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)44 herein.

           (b)  16  -    Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See
                         Exhibit 10(a)52 herein.

           (b)  17  -    Operating Agreement for the Joseph M. Farley Nuclear Plant between ALABAMA and Southern Nuclear dated as
                         of December 23, 1991.  See Exhibit 10(a)57 herein.

      #    (b)  18  -    The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)58 herein.

      #  * (b)  19  -    The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)59 herein.

           (b)  20  -    The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Three.  See Exhibit 10(a)60 herein.

         * (b)  21  -    Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan. See Exhibit
                         10(a)61 herein.

           (b)  22  -    The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Two.  See Exhibit 10(a)62 herein.

         * (b)  23  -    Amendment Number Three to The Southern Company Employee Stock Ownership Plan.  See Exhibit 10(a)63 herein.

           (b)  24  -    The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998.  See Exhibit
                         10(a)64 herein.


                                      E-20

<PAGE>

      #    (b)  25  -    The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)67 herein.

      #    (b)  26  -    The Southern Company Outside Directors Pension Plan.  See Exhibit 10(a)66 herein.

      #    (b)  27  -    Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto.  See
                         Exhibit 10(a)69 herein.

           (b)  28  -    The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
                         Amendment Number Three.  See Exhibit 10(a)71 herein.

         * (b)  29  -    Amendment Number Four to The Southern Company Pension Plan.  See Exhibit 10(a)72 herein.

      #  * (b)  30  -    The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999.  See Exhibit
                         10(a)73 herein.

      #  * (b)  31  -    The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)74 herein.

      #  * (b)  32  -    The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999.  See
                         Exhibit 10(a)70 herein.

      #    (b)  33  -    The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
                         Amendment Number Six.  See Exhibit 10(a)75 herein.

      #  * (b)  34  -    Amendment Number Seven to The Southern Company Performance Sharing Plan.  See Exhibit 10(a)76 herein.

      #    (b)  35  -    The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)77 herein.

      #  * (b)  36  -    Amendment Number One to The Southern Company Supplemental Benefit Plan.  See Exhibit 10(a)78 herein.

           (b)  37  -    Southern Company Change in Control Severance Plan, effective December 7, 1998. See Exhibit 10(a)79 herein.

         * (b)  38  -    Amendment Number One to Southern Company Change in Control Severance Plan.  See Exhibit 10(a)80 herein.

      #    (b)  39  -    Southern Company Executive Change in Control Severance Plan, effective December 7, 1998. See Exhibit
                         10(a)81 herein.

      #  * (b)  40  -    Amendment Number One to Southern Company Executive Change in Control Severance Plan.  See Exhibit 10(a)82
                         herein.

      #    (b)  41  -    Change in Control Agreement between SOUTHERN, ALABAMA and Banks Harry Farris.  See Exhibit 10(a)92 herein.


                                      E-21

<PAGE>

      #    (b)  42  -    Change in Control Agreement between SOUTHERN, ALABAMA and Elmer B. Harris.  See Exhibit 10(a)95 herein.

      #    (b)  43  -    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)  44  -    Deferred Compensation Plan for Directors of Alabama Power Company, Amended and Restated as of April 25,
                         1997.


         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 October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH 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.

                                      E-22

<PAGE>

           (c)  12  -    Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of
                         August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among GEORGIA, OPC, MEAG and Dalton. See
                         Exhibit 10(a)16 herein.

           (c)  13  -    Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among
                         GEORGIA, OPC, MEAG and Dalton.  See Exhibit 10(a)17 herein.

           (c)  14 -     Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption
                         Agreement dated as of November 16, 1983, between  GEORGIA and MEAG. See Exhibit 10(a)18 herein.

           (c)  15  -    Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between
                         GEORGIA and MEAG.  See Exhibit 10(a)19 herein.

           (c)  16  -    Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit
                         10(a)20 herein.

           (c)  17  -    Nuclear Operating Agreement between Southern Nuclear and GEORGIA dated as of July 1, 1993.  See Exhibit
                         10(a)21 herein.

           (c)  18  -    Pseudo Scheduling and Services Agreement between GEORGIA and MEAG dated as of April 8, 1997.  See Exhibit
                         10(a)22 herein.

           (c)  19  -    Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of April 19, 1977, between
                         GEORGIA  and Dalton.  See Exhibit 10(a)23 herein.

           (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. 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.

                                      E-23

<PAGE>


           (c)  25  -    Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of
                         March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988,
                         between  GEORGIA and GULF. See Exhibit 10(a)29 herein.

           (c)  26  -    Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA
                         and  GULF.  See Exhibit 10(a)30 herein.

           (c)  27  -    Plant Robert W. Scherer Unit No. Four Amended and Restated Purchase and Ownership Participation Agreement
                         by and among GEORGIA, FP&L and JEA dated as of December 31, 1990 and Amendment No. 1 dated as of June 15,
                         1994.  See Exhibit 10(a)31 herein.

           (c)  28  -    Plant Robert W. Scherer Unit No. Four Operating Agreement by and among GEORGIA, FP&L and JEA dated as of
                         December 31, 1990 and Amendment No. 1 dated as of June 15, 1994.  See Exhibit 10(a)32 herein.

           (c)           29 - Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May
                         18, 1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.

           (c)  30  -    Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1, dated August 30, 1984
                         and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS.
                         See Exhibit 10(a)34 herein.

           (c)  31  -    Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)35 herein.

           (c)  32  -    Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)36 herein.

           (c)  33  -    Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)37 herein.

           (c)  34  -    Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)38  herein.

           (c)  35  -    Power Purchase Agreement dated as of December 3, 1993 between GEORGIA and FPC.  See Exhibit 10(a)56 herein.

           (c)  36  -    Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)39 herein.

           (c)  37  -    Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)40 herein.

                                      E-24
<PAGE>

           (c)  38  -    Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18,
                         1988, between OPC and GEORGIA.  See Exhibit 10(a)41 herein.

           (c)  39  -    Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between
                         OPC and GEORGIA.  See Exhibit 10(a)42 herein.

         * (c)  40  -    Long Term Transaction Service Agreement between GEORGIA and OPC dated as of November 12, 1990.  See Exhibit
                         10(a)46 herein.

           (c)  41  -    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)47 herein.

           (c)  42  -    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)48 herein.

           (c)  43  -    Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between GEORGIA
                         and  OPC dated as of November 12, 1990.  See Exhibit 10(a)49 herein.

           (c)  44  -    Revised and Restated Integrated Transmission System Agreement between GEORGIA and Dalton dated as of
                         December 7, 1990.  See Exhibit 10(a)50 herein.

           (c)  45  -    Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December
                         7, 1990.  See Exhibit 10(a)51 herein.

           (c)  46  -    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)53 herein.

           (c)  47  -    Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and
                         SAVANNAH  dated as of December 15, 1992.  See Exhibit 10(a)54 herein.

           (c)  48  -    Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15,
                         1992.  See Exhibit 10(a)55 herein.

           (c)  49  -    Certificate of Limited Partnership of Georgia Power Capital.  (Designated in Certificate of Notification,
                         File No. 70-8461, as Exhibit B.)

           (c)  50  -    Amended and Restated Agreement of Limited Partnership of Georgia Power Capital, dated as of December 1,
                         1994.  (Designated in Certificate of Notification, File No. 70-8461, as Exhibit C.)

           (c)  51  -    Action of General Partner of Georgia Power Capital creating the Series A Preferred Securities. (Designated
                         in Certificate of Notification, File No. 70-8461, as Exhibit D.)


                                      E-25

<PAGE>

           (c)  52  -    Guarantee Agreement of GEORGIA dated as of December 1, 1994, for the benefit of the holders from time to
                         time  of the Series A Preferred Securities.  (Designated in Certificate of Notification, File No. 70-8461,
                         as  Exhibit G.)

      #    (c)  53  -    The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)58 herein.

      #  * (c)  54  -    The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)59 herein.

           (c)  55  -    The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Three.  See Exhibit 10(a)60 herein.

         * (c)  56  -    Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan.  See Exhibit
                         10(a)61 herein.

           (c)  57  -    The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Two.   See Exhibit 10(a)62 herein.

         * (c)  58  -    Amendment Number Three to The Southern Company Employee Stock Ownership Plan.  See Exhibit 10(a)63 herein.

           (c)  59  -    The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998.  See Exhibit
                         10(a)64 herein.

      #    (c)  60  -    The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)67 herein.

      #    (c)  61  -    The Southern Company Outside Directors Pension Plan.  See Exhibit 10(a)66 herein.

      #    (c)  62  -    Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto.  See
                         Exhibit 10(a)69 herein.

           (c)  63  -    The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
                         Amendment Number Three.  See Exhibit 10(a)71 herein.

         * (c)  64  -    Amendment Number Four to The Southern Company Pension Plan.  See Exhibit 10(a)72 herein.

      #  * (c)  65  -    The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999. See Exhibit
                         10(a)73 herein.

      #  * (c)  66  -    The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)74 herein.

      #  * (c)  67  -    The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999.  See
                         Exhibit  10(a)70 herein.


                                      E-26

<PAGE>

      #    (c)  68  -    The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
                         Amendment Number Six.  See Exhibit 10(a)75 herein.

      #  * (c)  69  -    Amendment Number Seven to The Southern Company Performance Sharing Plan.  See Exhibit 10(a)76 herein.

      #    (c)  70  -    The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit  10(a)77 herein.

      #  * (c)  71  -    Amendment Number One to The Southern Company Supplemental Benefit Plan.  See Exhibit 10(a)78 herein.

           (c)  72  -    Southern Company Change in Control Severance Plan, effective December 7, 1998.  See Exhibit 10(a)79 herein.

         * (c)  73  -    Amendment Number One to Southern Company Change in Control Severance Plan.  See Exhibit 10(a)80 herein.

      #    (c)  74  -    Southern Company Executive Change in Control Severance Plan, effective December 7, 1998.  See Exhibit
                         10(a)81 herein.

      #  * (c)  75  -    Amendment Number One to Southern Company Executive Change in Control Severance Plan.  See Exhibit 10(a)82
                         herein.

      #    (c)  76  -    Deferred Compensation Agreement between SOUTHERN, GEORGIA and Henry Allen Franklin.  See Exhibit 10(a)83
                         herein.

      #  * (c)  77  -    Amendment Number One and Assignment to SCS of Deferred Compensation Agreement between SOUTHERN, GEORGIA and
                         Henry Allen Franklin.  See Exhibit 10(a)84 herein.

      #    (c)  78  -    Deferred Compensation Agreement between SOUTHERN, GEORGIA and Warren Y. Jobe.  See Exhibit 10(a)86 herein.

      #    (c)  79  -    Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe.  See Exhibit 10(a)99 herein.

      #    (c)  80  -    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)  81  -    Deferred Compensation Plan For Directors of Georgia Power Company, Amended and Restated Effective November
                         19, 1986 and all amendments thereto through Amendment Number Three.



                                      E-27
<PAGE>


         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 October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)6 herein.

           (d)  3   -    Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March
                         1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between
                         GEORGIA and GULF.  See Exhibit 10(a)29 herein.

           (d)  4   -    Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA
                         and  GULF.  See Exhibit 10(a)30 herein.

           (d)  5   -    Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton,
                         GULF, FP&L and JEA.  See Exhibit 10(a)53 herein.

           (d)  6   -    Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18,
                         1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS.  See Exhibit 10(a)33 herein.

           (d)  7   -    Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1 dated August 30, 1984
                         and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS.
                         See Exhibit 10(a)34 herein.

           (d)  8   -    Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)35 herein.

           (d)  9   -    Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)36 herein.

           (d)  10  -    Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)37 herein.

           (d)  11  -    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)  12  -    Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)38  herein.

                                      E-28
<PAGE>

           (d)  13  -    Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)39 herein.

           (d)  14  -    Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)40 herein.

      #    (d)  15  -    The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)58 herein.

      #  * (d)  16  -    The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)59 herein.

           (d)  17  -    The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Three.  See Exhibit 10(a)60 herein.

         * (d)  18  -    Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan.  See Exhibit
                         10(a)61 herein.

           (d)  19  -    The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Two.  See Exhibit 10(a)62 herein.

         * (d)  20  -    Amendment Number Three to The Southern Company Employee Stock Ownership Plan.  See Exhibit 10(a)63 herein.

           (d)  21  -    The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998.  See Exhibit
                         10(a)64 herein.

      #    (d)  22  -    The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)67 herein.

      #    (d)  23  -    The Southern Company Outside Directors Pension Plan.  See Exhibit 10(a)66 herein.

      #    (d)  24  -    Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto.  See
                         Exhibit 10(a)69 herein.

           (d)  25  -    The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
                         Amendment Number Three.  See Exhibit 10(a)71 herein.

         * (d)  26  -    Amendment Number Four to The Southern Company Pension Plan.  See Exhibit 10(a)72 herein.

      #    (d)  27  -    The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)77 herein.

      #  * (d)  28  -    Amendment Number One to The Southern Company Supplemental Benefit Plan.  See Exhibit 10(a)78 herein.


                                      E-29

<PAGE>

           (d)  29  -    Southern Company Change in Control Severance Plan, effective December 7, 1998.  See Exhibit 10(a)79 herein.

         * (d)  30  -    Amendment Number One to Southern Company Change in Control Severance Plan.  See Exhibit 10(a)80 herein.

      #    (d)  31  -    Southern Company Executive Change in Control Severance Plan, effective December 7, 1998.  See Exhibit
                         10(a)81 herein.

      #  * (d)  32  -    Amendment Number One to Southern Company Executive Change in Control Severance Plan.  See Exhibit 10(a)82
                         herein.

      #    (d)  33  -    Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden.  See Exhibit 10(a)89 herein.

      #  * (d)  34  -    The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999.  See Exhibit
                         10(a)73 herein.

      #  * (d)  35  -    The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)74 herein.

      #  * (d)  36  -    The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999.  See
                         Exhibit 10(a)70 herein.

      #    (d)  37  -    The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
                         Amendment Number Six.  See Exhibit 10(a)75 herein.

      #  * (d)  38  -    Amendment Number Seven to The Southern Company Performance Sharing Plan.  See Exhibit 10(a)76 herein.

      #    (d)  39  -    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)  40  -    Supplemental Pension Agreement between ALABAMA, GULF and Travis J. Bowden.  See Exhibit 10(b)43 herein.

      #  * (d)  41  -    Deferred Compensation Plan For Directors of Gulf Power Company, Amended and Restated Effective January 1,
                         1987 and all amendments thereto through Amendment Number Three.


         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-30
<PAGE>

           (e)  2   -    Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)6 herein.

           (e)  3   -    Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18,
                         1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS.  See Exhibit 10(a)33 herein.

           (e)  4   -    Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1 dated August 30, 1984,
                         and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS.
                         See  Exhibit 10(a)34 herein.

           (e)  5   -    Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)35 herein.

           (e)  6   -    Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI,  SAVANNAH and SCS.  See Exhibit 10(a)36 herein.

           (e)  7   -    Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)37 herein.

           (e)  8   -    Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)38 herein.

           (e)  9   -    Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)39 herein.

           (e)  10  -    Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)40 herein.

           (e)  11  -    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)45 herein.

           (e)  12  -    Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA,  MISSISSIPPI and SCS.
                         See Exhibit 10(a)52 herein.

      #    (e)  13  -    The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)58 herein.

      #  * (e)  14  -    The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)59 herein.


                                      E-31

<PAGE>

           (e)  15  -    The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Three.  See Exhibit 10(a)60 herein.

         * (e)  16  -    Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan.  See Exhibit
                         10(a)61 herein.

           (e)  17  -    The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Two.  See Exhibit 10(a)62 herein.

         * (e)  18  -    Amendment Number Three to The Southern Company Employee Stock Ownership Plan.  See Exhibit 10(a)63 herein.

           (e)  19  -    The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998.  See Exhibit
                         10(a)64 herein.

      #    (e)  20  -    The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)67 herein.

      #    (e)  21  -    The Southern Company Outside Directors Pension Plan.  See Exhibit 10(a)66 herein.

      #    (e)  22  -    Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto.  See
                         Exhibit 10(a)69 herein.

           (e)  23  -    The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
                         Amendment Number Three.  See Exhibit 10(a)71 herein.

         * (e)  24  -    Amendment Number Four to The Southern Company Pension Plan.  See Exhibit 10(a)72 herein.

      #    (e)  25  -    The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)77 herein.

      #  * (e)  26  -    Amendment Number One to The Southern Company Supplemental Benefit Plan.  See Exhibit 10(a)78 herein.

           (e)  27  -    Southern Company Change in Control Severance Plan, effective December 7, 1998.  See Exhibit 10(a)79 herein.

         * (e)  28  -    Amendment Number One to Southern Company Change in Control Severance Plan.  See Exhibit 10(a)80 herein.

      #    (e)  29  -    Southern Company Executive Change in Control Severance Plan, effective December 7, 1998.  See Exhibit
                         10(a)81 herein.

      #  * (e)  30  -    Amendment Number One to Southern Company Executive Change in Control Severance Plan.  See Exhibit 10(a)82
                         herein.

                                      E-32

<PAGE>

      #    (e)  31  -    Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans.  See Exhibit 10(a)91 herein.

      #  * (e)  32  -    The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999.  See Exhibit
                         10(a)73 herein.

      #  * (e)  33  -    The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
                         1999. See Exhibit 10(a)74 herein.

      #  * (e)  34  -    The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999.  See
                         Exhibit 10(a)70 herein.

      #    (e)  35  -    The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
                         Amendment Number Six.  See Exhibit 10(a)75 herein.

      #  * (e)  36  -    Amendment Number Seven to The Southern Company Performance Sharing Plan.  See Exhibit 10(a)76 herein.

      #  * (e)  37  -    Deferred Compensation Plan for Directors of Mississippi Power Company, Amended and Restated Effective
                         January 1, 2000.


         SAVANNAH

           (f)  1   -    Service contract dated as of March 3, 1988, between SCS and SAVANNAH.  See Exhibit 10(a)3 herein.

           (f)  2   -    Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH 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)35 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)36 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)37 herein.

           (f)  6   -    Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF,
                         MISSISSIPPI, SAVANNAH and SCS.  See Exhibit 10(a)38 herein.

           (f)  7   -    Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)39 herein.


                                      E-33

<PAGE>

           (f)  8   -    Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                         SAVANNAH and SCS.  See Exhibit 10(a)40 herein.

           (f)  9   -    Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and
                         SAVANNAH dated as of December 15, 1992.  See Exhibit 10(a)54 herein.

           (f)  10  -    Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated December 15, 1992.
                         See Exhibit 10(a)55 herein.

      #    (f)  11  -    The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)58 herein.

      #  * (f)  12  -    The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
                         1999.  See Exhibit 10(a)59 herein.

           (f)  13  -    The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Three.  See Exhibit 10(a)60 herein.

         * (f)  14  -    Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan.  See Exhibit
                         10(a)61 herein.

           (f)  15  -    The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
                         amendments thereto through Amendment Number Two.  See Exhibit 10(a)62 herein.

         * (f)  16  -    Amendment Number Three to The Southern Company Employee Stock Ownership Plan.  See Exhibit 10(a)63 herein.

      #    (f)  17  -    Supplemental Executive Retirement Plan of SAVANNAH, Amended and Restated effective January 1, 1996 and all
                         amendments thereto through Amendment Number Two.  (Designated in SAVANNAH's Form 10-K for the year ended
                         December 31, 1995, File No. 1-5072, as Exhibit 10(f)17, in SAVANNAH's Form 10-K for the year ended December
                         31, 1996, File No. 1-5072, as Exhibit 10(f)20 and in SAVANNAH's Form 10-K for the year ended December 31,
                         1997, File No. 1-5072, as Exhibit 10(f)18.)

      #    (f)  18  -    Deferred Compensation Plan for Key Employees of SAVANNAH and all amendments thereto through Amendment
                         Number Three. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1994, File No. 1-5072,
                         as Exhibit 10(f)17, in SAVANNAH's Form 10-K for the year ended December 31, 1995, File No. 1-5072, as
                         Exhibit 10(f)19, in SAVANNAH's Form 10-K for the year ended December 31, 1996, File No. 1-5072, as Exhibit
                         10(f)22 and in SAVANNAH's Form 10-K for the year ended December 31, 1998, File No. 1-5072, as Exhibit
                         10(f)17.)

           (f)  19  -    The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998.  See Exhibit
                         10(a)64 herein.


                                      E-34

<PAGE>

      #    (f)  20  -    The Southern Company Outside Directors Pension Plan.  See Exhibit 10(a)66 herein.

      #    (f)  21  -    Deferred Compensation Plan for Directors of SAVANNAH.  (Designated in SAVANNAH's Form 10-K for the year
                         ended  December 31, 1997, File No. 1-5072, as Exhibit 10(f)23.)

      #    (f)  22  -    Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto.  See
                         Exhibit 10(a)69 herein.

           (f)  23  -    The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
                         Amendment Number Three.  See Exhibit 10(a)71 herein.

         * (f)  24  -    Amendment Number Four to The Southern Company Pension Plan.  See Exhibit 10(a)72 herein.

      #    (f)  25  -    The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)77 herein.

      #  * (f)  26  -    Amendment Number One to The Southern Company Supplemental Benefit Plan.  See Exhibit 10(a)79 herein.

           (f)  27  -    Southern Company Change in Control Severance Plan, effective December 7, 1998.  See Exhibit 10(a)79 herein.

         * (f)  28  -    Amendment Number One to Southern Company Change in Control Severance Plan.  See Exhibit 10(a)80 herein.

      #    (f)  29  -    Southern Company Executive Change in Control Severance Plan, effective December 7, 1998.  See
                         Exhibit 10(a)81 herein.

      #  * (f)  30  -    Amendment Number One to Southern Company Executive Change in Control Severance Plan.  See Exhibit 10(a)82
                         herein.

      #    (f)  31  -    Change in Control Agreement between SOUTHERN, SAVANNAH and G. Edison Holland, Jr.  See Exhibit 10(a)96
                         herein.

      #    (f)  32  -    The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998.  See
                         Exhibit 10(a)67 herein.

      #  * (f)  33  -    The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999.  See Exhibit
                         10(a)73 herein.

      #  * (f)  34  -    The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective
                         January 1, 1999.   See Exhibit 10(a)74 herein.

      #  * (f)  35  -    The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999. See Exhibit
                         10(a)70 herein.


                                      E-35
<PAGE>

      #    (f)  36  -    The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
                         Amendment Number Six.  See Exhibit 10(a)75 herein.

      #  * (f)  37  -    Amendment Number Seven to The Southern Company Performance Sharing Plan.  See Exhibit 10(a)76 herein.

      #    (f)  38  -    Supplemental Pension Agreement between SAVANNAH, GULF and G. Edison Holland, Jr.  See Exhibit 10(d)38
                         herein.

(21)     Subsidiaries of Registrants

         SOUTHERN

         * (a)      -    Subsidiaries of Registrant.

         ALABAMA

         * (b)      -    Subsidiaries of Registrant.

         GEORGIA

         * (c)      -    Subsidiaries of Registrant.

         GULF

         * (d)      -    Subsidiaries of Registrant.

         MISSISSIPPI

         * (e)      -    Subsidiaries of Registrant.

         SAVANNAH

         * (f)      -    Subsidiaries of Registrant.


(23)     Consents of Experts and Counsel

         SOUTHERN

         * (a)      -    The consent of Arthur Andersen LLP is contained herein at page IV-5.

         ALABAMA

         * (b)      -    The consent of Arthur Andersen LLP is contained herein at page IV-6.

         GEORGIA

         * (c)      -    The consent of Arthur Andersen LLP is contained herein at page IV-7.

                                      E-36

<PAGE>


         GULF

         * (d)      -    The consent of Arthur Andersen LLP is contained herein at page IV-8.

         MISSISSIPPI

         * (e)      -    The consent of Arthur Andersen LLP is contained herein at page IV-9.

         SAVANNAH

         * (f)      -    The consent of Arthur Andersen LLP is contained herein at page IV-10.

 (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.

(27)     Financial Data Schedule

         SOUTHERN

           (a)      -    Financial Data Schedule.  (Designated in Form 8-K dated February 16, 2000, File No. 1-3526, as Exhibit 27.)

         ALABAMA

           (b)      -    Financial Data Schedule.  (Designated in Form 8-K dated February 16, 2000, File No. 1-3164, as Exhibit 27.)

                                      E-37

<PAGE>


         GEORGIA

           (c)      -    Financial Data Schedule.  (Designated in Form 8-K dated February 16, 2000, File No. 1-6468, as Exhibit 27.)

         GULF

           (d)      -    Financial Data Schedule.  (Designated in Form 8-K dated February 16, 2000, File No. 0-2429, as Exhibit 27.)

         MISSISSIPPI

           (e)      -    Financial Data Schedule.  (Designated in Form 8-K dated February 16, 2000, File No. 0-6849, as Exhibit 27.)

         SAVANNAH

           (f)      -    Financial Data Schedule.  (Designated in Form 8-K dated February 16, 2000, File No. 1-5072, as Exhibit 27.)


</TABLE>
                                      E-38