View source for NL-05-1222, Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.21)

{{Adams
| number = ML052100358
| issue date = 07/27/2005
| title = Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.21)
| author name = Aubuchon R
| author affiliation = Georgia Power Co
| addressee name = 
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000321, 05000366, 05000424, 05000425
| license number = DPR-057, NPF-005
| contact person = 
| case reference number = NL-05-1222
| document type = Annual Report, Letter type:NL
| page count = 70
}}

=Text=
{{#Wiki_filter:GEORGIA A POWER July 27, 2005                                                                  A SOUTHERN COMPANY Docket Nos.:     50-321     50-424                                         NL-05-1222 50-366     50-425 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin I. Hatch Nuclear Plant Vogtle Electric Generating Plant Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.2 1)
Ladies and Gentlemen:
Enclosed you will find the following financial information pursuant to Section 140.21 of 10 CFR Part 140 that each licensee is required to furnish as a guarantee of payment of deferred premiums for each operating reactor over 100 Mw(e):
: 1. An Annual Report containing certified financial statements for calendar year 2004.
: 2. A set of quarterly financial statements for the period ending June 30, 2005.
: 3. A one year projected Cash Flows Statement for period January 1, 2006, through December 31, 2006.
Should you have any questions in connection with our response, please contact me at (404) 506-7952 or Jan Miller at (404) 506-6690. This letter contains no NRC commitments.
Sincerely, Robert A. Aubuchon Enclosures pMoo

U. S. Nuclear Regulatory Commission NL 1222 Page 2 cc:   Southern Nuclear Operating Company Mr. J. T. Gasser, Executive Vice President Mr. H. L. Sumner, Jr., Vice President, Plant Hatch Mr. D. E. Grissette, Vice President, Plant Vogtle Mr. G. R Frederick, General Manager - Plant Hatch Mr. T. E. Tynan, General Manager - Plant Vogtle RType: CHAO2.004; CVC7000 U. S. Nuclear Regulatorv Commission Dr. W. D. Travers, Regional Administrator Mr. C. Gratton, NRR Project Manager - Hatch Mr. C. Gratton, NRR Project Manager - Vogtle Mr. D. S. Simpkins, Senior Resident Inspector - Hatch Mr. G. J. McCoy, Senior Resident Inspector - Vogtle

GEORGIA POWER COMPANY CONDENSED STATEMENTS OF INCOME (UNAUDITED)
(Stated in Thousands of Dollars)
For the Three Months              For the Six Months Ended June 30,                  Ended June 30, 2005          2004               2005            2004 OPERATING REVENUES:
Retail sales                                           $1,227,087      $1,199,220         $2,412,323      $2,237,015 Sales for resale-Non-affiliates                                           126,000          61,597            238,852        127,053 Affiliates                                                 54,743         48,950              80,374       103,092 Other revenues                                               51,358         43,395              98,069         85,391 Total operating revenues                             1,459,188      1,353,162          2,829,618       2,552,551 OPERATING EXPENSES:
Operation-Fuel                                                   412,050         324,220            721,316        609,434 Purchased power-Non-affiliates                                          64,523         97,392            117,497        160,081 Affiliates                                            140,800         139,319            360,804        274,461 Other                                                  223,471         220,799            425,550        419,192 Maintenance                                                123,575         124,675            240,225        233,143 Depreciation and amortization                              124,999          68,542            248,099        136,279 Taxes other than Income taxes                                58,648         56,488            119,407        112,920 Total operating expenses                             1,148,066       1,031,435          2,232,898      1,945,510 OPERATING INCOME                                             311,122         321,727            596,720        607,041 OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction          7,935           4,700             17,192          8,047 Interest Income                                                  31          1,768                502          4,120 Interest expense, net of amounts capitalized               (55,174)       (48,293)          (105,594)        (93,943)
Interest expense to affiliate trusts                       (14,877)       (14,810)            (29,755)       (14,810)
Distributions on preferred securities of subsidiaries                                                                                       -     (15,839)
Other Income (expense), net                                   2,821         (5,613)                (21)      (10,008)
Total other Income and (expense)                        (59,264)       (62,248)          (117,676)      (122,433)
EARNINGS BEFORE INCOME TAXES                                 251,858         259,479            479,044        484,608 Income taxes                                                94,140        103,597            178,794        184,717 NET INCOME                                                   157,718         155,882            300,250        299,891 DIVIDENDS ON PREFERRED STOCK                                       167            167                335             335 NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK                                          $157,551        $155,715           $299,915       $299,556 Note: Certain prior period amounts have been reclassified to conform with current period presentation.

GEORGIA POWER COMPANY CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Stated in Thousands of Dollars)
FOR THE SIX MONTHS ENDED JUNE 2005                   2004 OPERATING ACTIVITIES:
Net income                                                                      $300,250              $299,891 Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization                                                 292,447               177,927 Deferred income taxes and investment tax credits, net                           89,724              127,958 Pension, postretirement, and other employee benefits                             5,318              (11,339)
Other, net                                                                       2,052              (13,289)
Changes in certain current assets and liabilities -
Receivables, net                                                             (247,991)             (146,027)
Fossil fuel stock                                                              (23,692)              (6,309)
Materials and supplies                                                         (16,024)              (2,680)
Other current assets                                                            14,055               29,779 Accounts payable                                                               (59,236)              (4,474)
Taxes accrued                                                                   43,098              (78,952)
Other current liabilities                                                      (42,595)              25,648 NET CASH PROVIDED FROM OPERATING ACTIVITIES                                         357,406               398,133 INVESTING ACTIVITIES:
Gross property additions                                                        (408,120)             (672,424)
Cost of removal net of salvage                                                   (10,359)              (14,236)
Other                                                                             (15,044)             (12,844)
NET CASH USED FOR INVESTING ACTIVITIES                                             (433,523)             (699,504)
FINANCING ACTIVITIES:
Increase (decrease) in notes payable, net                                        171,669               234,749 Proceeds   -
Senior notes                                                                 375,000               350,000 Pollution control bonds                                                      185,000 Shares subject to mandatory redemption                                                -            200,000 Capital contributions from parent company                                    100,000               223,000 Redemptions    -
Pollution control bonds                                                      (85,000)
Shares subject to mandatory redemption                                                 -           (200,000)
Senior notes                                                                 (300,000)             (200,000)
Special deposits - redemption funds                                             (100,000)
Payment of preferred stock dividends                                                 (211)                (209)
Payment of common stock dividends                                               (278,050)             (282,750)
Other                                                                            (16,494)              (11,860)
NET CASH PROVIDED FROM FINANCING ACTIVITIES                                           51,914              312,930 NET CHANGE IN CASH AND CASH EQUIVALENTS                                             (24,203)               11,559 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                      33,497                8,699 CASH AND CASH EQUIVALENTS AT END OF PERIOD                                            $9.294              S20.258 Note: Certain prior period amounts have been reclassified to conform with current period presentation.

GEORGIA POWER COMPANY CONDENSED BALANCE SHEETS (UNAUDITED)
(Stated in Thousands of Dollars)
At June 30,      At June 30, 2005              2004 ASSETS CURRENT ASSETS:
Cash and cash equivalents                                           $9,294         $20,258 Receivables -
Customer accounts receivable                                   361,605          300,311 Unbilled revenues                                              168,392          167,852 Under recovered regulatory clause revenue                      153,301          254,428 Other accounts and notes receivable                            185,223            77,475 Affiliated companies                                             31,350           30,935 Accumulated provision for uncollectible accounts                                        (6,575)          (6,025)
Fossil fuel stock, at average cost                                207,959          143,846 Materials and supplies, at average cost                           286,446          273,720 Other                                                               91,819           76,788 Total Current Assets                                      1,488,814        1,339,588 PROPERTY, PLANT AND EQUIPMENT:
In service                                                     19,327,416       18,472,477 Less accumulated provision for depreciation                                         -
7,392,744        7,068,465 11,934,672       11,404,012 Nuclear fuel, at amortized cost                                   129,567          116,191 Construction work in progress                                     443,904          639,952 Total Property, Plant and Equipment                      12,508,143       12,160,155 OTHER PROPERTY AND INVESTMENTS:
Equity investments in unconsolidated subsidiaries                   65,949           68,703 Nuclear decommissioning trusts                                    466,656          437,441 Other                                                               64,472           64,891 Total Other Property and Investments                       597,077          571,035 DEFERRED CHARGES AND OTHER ASSETS:
Deferred charges related to income taxes                          506,259          504,470 Prepaid pension costs                                             460,865          426,899 Unamortized debt issuance expense                                   88,638           74,852 Unamortized loss on reacquired debt                                172,961         182,286 Deferred under recovered regulatory clause revenues               362,692 Other                                                              170,698          160,596 Total Deferred Charges and Other Assets                  1,762,113        1,349,103 TOTAL ASSETS                                                   $16.356,147       $15,419,881

GEORGIA POWER COMPANY CONDENSED BALANCE SHEETS (UNAUDITED)
(Stated in Thousands of Dollars)
At June 30,      At June 30, 2005              2004 LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES:
Securities due within one year                                  $402,603         $302,401 Notes payable                                                     379,902          372,027 Accounts payable -
Affiliated companies                                           157,765          154,541 Other                                                          248,786          236,621 Customer deposits                                                 122,446          109,204 Taxes accrued Income taxes                                                   183,985          172,250 Other                                                          115,596          104,271 Interest accrued                                                    78,595           71,861 Vacation pay accrued                                                44,179           42,749 Other                                                             186,640          195,185 Total Current Liabilities                                    1,920,497        1,761,110 LONG-TERM DEBT                                                     3,931,825        3,611,092 LONG-TERM DEBT PAYABLE TO AFFILIATED TRUSTS                          969.073          969.073 MANDATORILY REDEEMABLE PREFERRED SECURITIES DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes                               2,598,783        2,358,072 Deferred credits related to income taxes                          164,588          178,986 Accumulated deferred investment tax credits                                                        293,872          306,262 Employee benefits provisions                                      346,916          306,543 Asset retirement obligations                                      520,298          490,164 Other                                                             581,077          630,579 Total Deferred Credits and Other Liabilities                 4,505,534        4,270,606 PREFERRED STOCK                                                    14,609           14,609 COMMON STOCKHOLDER'S EQUITY:
Common stock                                                     344,250          344,250 Paid-in capital                                                2,589,121        2,437,069 Retained earnings                                              2,124,641        2,027,103 Accumulated other comprehensive income                             (43,403)         (15,031)
Total Common Stockholder's Equity                           5,014,609        4,793,391 TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY               T116,356,147      $15,419,881

7                               GEORGIA POWER COMPANY PROJECTED STATEMENT OF CASH FLOWS 2006 FORECAST (Stated in Thousands of Dollars) 2006 FORECAST OPERATING ACTIVITIES Net income before preferred dividends                                      $717,326 Principal noncash items-Depreciation and amortization                                             580,389 Deferred Income taxes, net                                                (76,524)
Allowance for equity funds used during construction                       (36,838)
Pension, postretirement and other employee benefits                         (2,962)
Other, net                                                                 32,072 Change in current assets & liabilities-Receivables                                                               206,598 Inventories                                                               (92,858)
Accounts payable                                                           (1,578)
Other current assets and liabilities                                       50,894 NET CASH PROVIDED FROM OPERATING ACTIVITIES                             1,376,519 INVESTING ACTIVITIES Gross property additions                                                  (1,083,384)
Cost of removal, net of salvage                                              (24,430)
Allowance for equity funds used during construction                           36,838 Other property and Investments                                                (8,315)
NET CASH USED FOR INVESTING ACTIVITIES                                 (1,079,291)
FINANCING ACTIVITIES Increase in notes payable, net                                                120,607 Proceeds   -
Senior notes                                                               150,000 Preferred stock                                                            115,000 Capital contributions from parent company                                   46,943 Redemptions -
Senior notes                                                              (150,000)
Capitalized leases                                                          (2,708)
Payment of preferred stock dividends                                           (3,488)
Payment of common stock dividends                                            (568,000)
Other                                                                          (5,582)
NET CASH USED FOR FINANCING ACTIVITIES                                   (297,228)
NET INC (DEC) IN CASH AND TEMPORARY CASH INVESTMENTS                                  $0 CASH AND TEMPORARY CASH INVESTMENTS AT BEG OF PERIOD                            $15,000 CASH AND TEMPORARY CASH INVESTMENTS AT END OF PERIOD                            $15,000

2004 Annual Report Georgia Power Company GEORGIA A POWER A SOUTHERN COMPANY

CONTENTS Georgia Power Company 2004 Annual Report 1           

==SUMMARY==

2            LETTER TO INVESTORS 4           REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 5           MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION 25            FINANCIAL STATEMENTS 31            NOTES TO FINANCIAL STATEMENTS 56            SELECTED FINANCIAL AND OPERATING DATA 58            DIRECTORS AND OFFICERS 60            CORPORATE INFORMATION

==SUMMARY==

Percent 2004      2003     Change Financial Highlights (in millions):
Operating revenues                                      $5,371    $4,914      9.3 Operating expenses                                      $4,112    $3,690     11.4 Net income after dividends on preferred stock             $658      $631      4.3 Operating Data:
Kilowatt-hour sales (in millions):
Retail                                         77,904    75,018      3.8 Sales for resale - non-affiliates               5,970     8,836    (32.5)
Sales for resale - affiliates                   4,783     5,844    (18.2)
Total                                          88,657    89,698     (1.2)
Customers served at year-end (in thousands)              2,078     2,038      2.0 Peak-hour demand (in megawatts)                         15,180    14,826      2.4 Capitalization Ratios (percent):
Common stock equity                                        51.0     49.0 Preferred stock                                             0.2       0.2 Mandatorily redeemable preferred securities                  -       10.2 Long-term debt payable to affiliated trusts                10.1 Long-term debt                                             38.7     40.6 Return on Average Common Equity                  (percent)      13.95     14.05 Ratio of Earnings to Fixed Charges               (times)          5.11     5.01 1

LETTER TO INVESTORS Georgia Power 2004 Annual Report Looking back, 2004 will likely be remembered as the year of the hurricanes. Georgia Power employees, along with others across our Southern Company system, battled an unprecedented four hurricanes in six weeks to restore power throughout the Southeast.
Georgia Power not only achieved high marks in restoration and reliability, but we also demonstrated once again that we can take care of our customers' needs, improve efficiency, support our communities and meet the growing demand for energy in this vibrant state.
Strong operational excellence, combined with exceptional financial performance in 2004, resulted in an outstanding year for the company.
Georgia Power's 2004 earnings totaled $658 million, a $27 million, or 4.3 percent increase, from 2003. We earned a 13.95 percent total company return on average common equity during 2004. Georgia Power had a net plant in service investment of
$11.5 billion at the end of the year, with total assets of $15.8 billion. Operating revenues for 2004 were $5.4 billion.
Our solid results for 2004 were achieved, despite the extensive damage and economic disruption caused by Hurricanes Charley, Frances, Ivan and Jeanne in August and September.
Ivan was the worst storm in Southern Company's history, knocking out power to hundreds of thousands of Georgia Power customers. Because of the outstanding response by Georgia Power employees and our sister companies, with assistance from many other companies and organizations, we restored service to our customers in record time.
Continued economic vitality in Georgia helped boost electricity sales and was a key contributor to our strong financial results last year. Businesses and individuals continued to be drawn to the state, increasing the number of customers Georgia Power serves to approximately 2.1 million in 2004, a 2 percent increase from the previous year.
Our retail sales of electricity climbed 3.8 percent in 2004 as we maintained an excellent reliability record. In fact, Georgia Power plants achieved a superior peak season equivalent forced outage rate of 0.81 percent, surpassing our peak goal of 2.9 percent.
As demand for electricity increases, we continue to provide options for our customers to help manage their consumption of electricity.
Nearly 20,000 customers now participate in the Power Credit program, an electricity demand-saving service designed to efficiently control the amount of electricity a residential customer's air conditioner uses during peak demand periods in the summer 2

months. The program helps Georgia Power meet demand and lower its overall cost to serve customers during peak periods.
Improving efficiency across the company is one of our main goals. In 2004, we replaced 92-year-old turbines at Plant Goat Rock with more efficient models that will require less maintenance and generate more power. The turbines also have a more "fish friendly" design.
Our environmental efforts are just one way we demonstrate our commitment to being a Citizen Wherever We Serve. Through our economic development activities, Georgia Power was instrumental in locating 65 new or expanding businesses in the state, which will bring a record $1.5 billion in new capital investment and 8,678 new jobs to our state.
To meet growing customer demand for electricity, the Georgia Public Service Commission approved a rate increase for Georgia Power late last year that will mean a 4.2 percent, or about $3.10 a month, change in the average residential customer's bill, beginning in 2005.
This is the company's first base rate increase in 13 years - even though we're serving 486,000 more customers. The rate increase will recover higher operations and investment costs, including power lines, new generation sources, environmental controls and other necessary infrastructure to meet demand.
Increasing supplier diversity is a key goal for our company. Last year, we spent $157.6 million, or 13.5 percent of our total procurement dollars, excluding fuel, with minority-and female-owned businesses. We surpassed our goal of 11.25 percent and have set a goal of 12.35 percent for 2005.
Without a doubt, our employees delivered another outstanding performance in 2004 by continuing to focus on the fundamentals of providing customers with reliable, cost-effective power and great service. We will continue that success in 2005 as we work to meet our state's growing demand for energy.
Sincerely, A/,4--                   -
Michael D. Garrett April 18, 2005 3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMI Georgia Power Company:
In our opinion, the financial statements (pages 25 to We have audited the accompanying balance sheets and           55) present fairly, in all material respects, the financial statements of capitalization of Georgia Power Company (a      position of Georgia Power Company at December 31, wholly owned subsidiary of Southern Company) as of            2004 and 2003, and the results of its operations and its December 31, 2004 and 2003, and the related statements        cash flows for each of the three years in the period ended of income, comprehensive income, common stockholder's         December 31, 2004, in conformity with accounting equity, and cash flows for each of the three years in the     principles generally accepted in the United States of period ended December 31, 2004. These financial               America.
statements are the responsibility of Georgia Power Company's management. Our responsibility is to express            As discussed in Note I to the financial statements, in an opinion on these financial statements based on our         2003 Georgia Power Company changed its method of audits.                                                       accounting for asset retirement obligations.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight 7;/            LLP Board (United States). Those standards require that we        Atlanta, Georgia plan and perform the audit to obtain reasonable assurance     February 28, 2005 about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.
4

MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 2004 Annual Report OVERVIEW                                                             The Company's 2004 results compared to its targets for each of these indicators are reflected in the Business Activities                                             following chart.
Georgia Power Company (Company) operates as a                         Key                  2004                 2004 vertically integrated utility providing electricity to retail    Performance             Target                Actual customers within its traditional service area located              Indicator          Performance          Performance Customer           Top quartile         Top quartile within the State of Georgia and to wholesale customers Satisfaction        performance in the Southeast.
on national surveys Many factors affect the opportunities, challenges                                                         0.81%
Peak Season          2.90% or less and risks of the Company's primary business of EFOR selling electricity. These factors include the ability to ROE                13.70%               13.95%
maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and                          The strong financial performance achieved in increasingly stringent environmental standards. In              2004 reflects the focus that management places on 2004, the Company completed a major retail rate                 these indicators, as well as the commitment shown by proceeding that should help provide future earnings             employees in achieving or exceeding management's stability. This regulatory action will also enable the          expectations.
recovery of substantial capital investments to Earnings facilitate the continued reliability of the transmission and distribution network and continue environmental             The Company's 2004 earnings totaled $658 million improvements at the generating plants. Appropriately            representing a $27 million (4.3 percent) increase over balancing environmental expenditures with customer 2003. Operating income increased in 2004 due to higher prices will continue to challenge the Company for the foreseeable future.                                             base retail revenues attributable to more favorable weather and customer growth during the year, partially Key PerformanceIndicators                                       offset by higher non-fuel operating expenses. In addition, lower depreciation and amortization expense in The Company strives to maximize shareholder value               the final year of a Georgia Public Service Commission while providing low-cost energy to more than 2                  (PSC) retail rate plan that was effective January 2002 million customers by focusing on several key                    (2001 Retail Rate Plan) significantly offset increased indicators. These include customer satisfaction, peak           purchased power capacity expenses. The Company's season equivalent forced outage rate (Peak Season               2003 earnings totaled $631 million, representing a $13 EFOR), and return on equity (ROE). The Company's                million (2.1 percent) increase over 2002. Operating financial success is directly tied to the satisfaction of       income increased in 2003 despite lower base retail its customers. Key elements of ensuring that                    revenues resulting from the extremely mild summer satisfaction include outstanding service, high                  weather. Higher wholesale revenues and lower non-fuel reliability, and competitive prices. Management uses            operating expenses contributed to the increase. The nationally recognized customer satisfaction surveys             Company's 2002 earnings totaled $618 million, and reliability indicators to evaluate the Company's representing an $8 million (1.2 percent) increase over results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations          2001 resulting from lower financing costs and a lower during the months when generation needs are greatest.           effective tax rate due to the realization of certain state The rate is calculated by dividing the number of hours          tax credits. Operating income declined slightly in 2002.
of forced outages by total generation hours. ROE is a           Lower retail and wholesale revenues, higher other performance standard used by the investment                     operating and maintenance expenses, and increased community and many regulatory agencies.                         purchased power capacity expenses were significantly offset by lower depreciation and amortization expense as a result of the 2001 Retail Rate Plan.
5

MANAGEMENT'S DISCUSSION AND ANALYSIS                              (continued)
Georgia Power Company 2004 Annual Report RESULTS OF OPERATIONS                                                        Revenues A condensed income statement for the Company is as                           Operating revenues in 2004, 2003, and 2002 and the follows:                                                                     percent of change from the prior year are as follows:
Amount Increase (Decrease)                                              -
2004        2003        2002 Amount            From Prior Year                                                             (in millions) 2004     2004         2003 2002                  Retail - prior year             $4,310     $4,288 (in millions)
                                                                                                                                     $4,349 Change in -
Operating revenues       $5,371      $457         $ 92 $(144)                  Base rates                                              (118)
Fuel                       1,233        128         101      64                Sales growth and other           151          30            2 Purchased power              976        200          92     (87)               Weather                           32         (66)         82 Other operation                                                                Fuel cost recovery and maintenance          1,400        153         (78)     85                    and other                    284          58         (27)
Depreciation and                                                             Retail - current year            4,777      4,310        4,288 amortization               275        (74)        (54)   (197)             Sales for resale -
Taxes other than                                                               Non-affiliates                   247        260          271 income taxes               228          15         11       (1)              Affiliates                       166         175          98 Total operating                                                              Total sales for resale             413        435          369 expenses                 4,112        422          72    (136)             Other operating revenues           181         169         165 Operating income           1,259          35         20       (8)            Total operating revenues       $5,371      $4,914 $4,822 Total other income                                                           Percent change                     9.3%        1.9%       (2.9)%
and (expense)             (221)          5          2        9 Income taxes                 379          13          9       (7)                 Retail base revenues of $3.2 billion in 2004 Net income                   659          27         13        8             increased by $183 million (6.0 percent) from 2003 Dividends on                                                                 primarily due to an improved economy, customer preferred stock              1           -           -        -            growth, generally higher prices to the Company's large Net income after                                                             business customers, and more favorable weather. Retail dividends on                                                               base revenues of $3 billion in 2003 decreased by $36 preferred stock        $ 658       $ 27         $ 13   $     8             million (1.2 percent) from 2002 primarily due to extremely mild summer temperatures in 2003 and the sluggish economy. Retail base revenues of $3.1 billion in 2002 decreased by $34 million (1.1 percent) from 2001 primarily due to a base rate reduction effective January 2002 under the 2001 Retail Rate Plan and generally lower prices to large business customers.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses -- including the fuel component of purchased energy -- and do not affect net income. In August 2003, the Georgia PSC issued an order allowing the Company to increase customer fuel rates to recover existing under recovered deferred fuel costs. In recent months, the Company has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs. On February 18, 2005, the Company filed a 6

MANAGEMENT'S DISCUSSION AND ANALYSIS                        (continued)
Georgia Power Company 2004 Annual Report request with the Georgia PSC for a fuel cost recovery                  Plant Dahlberg to Southern Power Company (Southern rate increase. In the ordinary course, these new rates                 Power) in July 2001.
will be effective June 1, 2005 following a hearing before and approval by the Georgia PSC. In its filing, the                          Revenues from sales to affiliated companies within Company asked that the Georgia PSC accept the new                      the Southern Company electric system, as well as rate, effective April 1, 2005, prior to a formal hearing on            purchases of energy, will vary from year to year the Company's request. This action, if taken by the                     depending on demand and the availability and cost of Georgia PSC, would serve to mitigate expected increases                 generating resources at each company. These affiliated in the under recovered balance during April and May,                    sales and purchases are made in accordance with the but will not preclude the Georgia PSC from                              affiliate company interchange agreement, as approved by subsequently adjusting the rates. The requested                         the Federal Energy Regulatory Commission (FERC). In increase, representing an annual increase in revenues of                2004, kilowatt-hour (KWH) energy sales to affiliates approximately 11.7 percent, will allow for the recovery                 decreased 18.2 percent due to lower demand. However, of fuel costs based on an estimate of future fuel costs, as             the decline in associated revenues was only 4.9 percent well as the collection of the existing under recovery of                due to higher fuel prices. In 2003, KWH energy sales to fuel costs. The Company's under recovered fuel costs as                affiliates increased 47.5 percent due to the combination of January 31, 2005 totaled $390 million. The Georgia                  of increased demand by Southern Power to meet PSC will examine the Company's fuel expenditures and                    contractual obligations and the availability of power due determine whether the proposed fuel cost recovery rate                 to milder-than-normal weather in the Company's service is just and reasonable before issuing its decision in May              territory. These transactions do not have a significant 2005. The final outcome of the filing cannot be                        impact on earnings since this energy is generally sold at determined at this time. See Note 3 to the financial                    marginal cost.
statements under "Fuel Cost Recovery" for further information regarding this filing.                                          Other operating revenues increased $11.7 million (6.9 percent) in 2004 primarily due to higher revenues Wholesale revenues from sales to non-affiliated                   from outdoor lighting of $4.2 million and pole utilities were:                                                        attachment rentals of $4.9 million and higher gains on sales of emission allowances of $2 million. Other 2004        2003       2002             operating revenues increased $4 million (2.4 percent) in (in millions)                  2003 primarily due to an increase in the open access Unit power sales --                                                    transmission tariff rate, which increased revenues $7 Capacity                    $31         $34        $ 34             million, and higher revenues from increased customer Energy                         33          31        34             demand for outdoor lighting services of $4 million, Other power sales --                                                   partially offset by lower revenues from the rental of Capacity                       75          93        62             electric property of $4 million. Other operating revenues Energy                        108         102       141             in 2002 increased $14 million (9.5 percent) primarily due to the collection of new late payment fees approved Total                          $247        $260       $271 under the 2001 Retail Rate Plan of $7 million and higher Revenues from unit power sales contracts remained                 revenues from increased customer demand for outdoor relatively constant in 2004. Revenues from unit power                  lighting services of $5 million and the transmission of contracts decreased slightly in 2003 due to decreased                  electricity of $3 million.
energy sales. Revenues from other non-affiliated sales decreased $12 million (6.2 percent), $8 million (3.9 percent), and $102 million (33.4 percent) in 2004, 2003, and 2002, respectively, primarily due to fluctuations in off-system sale transactions that were generally offset by corresponding purchase transactions. These transactions had no significant effect on income. In 2002, revenues also decreased $37 million as a result of transferring 7

MANAGEMENT'S DISCUSSION AiND ANALYSIS (continued)
Georgia Power Company 2004 Annual Report Energy Sales                                                  generated, and the average cost of purchased power per net KWH were as follows:
KWH sales for 2004 and the percent change by year were as follows:                                                                               2004      2003       2002 Total generation KWH                 Percent Change          (billions of KWH)               71.5      73.1       70.4 2004       2004       2003     2002     Sources of generation (in billions)                               (percent) --
Residential            22.9        5.3%      (I.7)%   10.1%        Coal                         75.4      75.4       77.4 Commercial             28.0        4.0       (0.1)     1.7         Nuclear                      22.5     21.6        21.1 Industrial             26.4        2.5       (0.1)     1.5         Hydro                         2.0       2.7        1.2 Other                   0.6        1.1        0.4      1.7         Oil and gas                   0.1       0.3        0.3 Total retail           77.9        3.8       (0.5)     4.0    Average cost of fuel per net Sales for resale -                                              KWH generated Non-affiliates        6.0     (32.5)        9.5     (0.5)     (cents) --                      1.55      1.46       1.42 Affiliates           4.8     (18.2)      47.5      26.5    Average cost of purchased Total sales for                                                 power per net KWH resale              10.8     (26.8)      22.0       7.0         (cents) --                   5.17     4.03        3.29 Total sales            88.7       (1.2)       2.6      4.4 Fuel expense increased 11.6 percent in 2004 Residential KWH sales increased 5.3 percent in           primarily due to an increase in the average cost of fuel.
2004 due to more favorable weather and a 1.9 percent          Fuel expense increased 10.1 percent in 2003 due to an increase in residential customers. Commercial KWH             increase in generation of 3.9 percent because of higher sales increased 4.0 percent in 2004 due to an improved        wholesale energy demands and a 2.8 percent higher economy and a 2.8 percent increase in commercial              average cost of fuel due to the higher prices of coal and customers. Industrial sales increased 2.5 percent in 2004     natural gas in 2003. Fuel expense increased 6.8 percent due to the improved economy. Residential KWH sales            in 2002 due to a 2.2 percent increase in generation decreased 1.7 percent in 2003 due to the effect of the        because of higher energy demands and a 2.9 percent milder summer weather, despite the 2.0 percent increase       higher average cost of fuel due to the higher cost of coal.
in residential customers. Commercial KWH sales in 2003 declined slightly due to the milder summer                    Purchased power expense increased $200 million weather, while industrial KWH sales declined slightly         (25.9 percent) in 2004 primarily due to a 38.5 percent due to the sluggish economy. Residential KWH sales            increase in the average cost of fuel per net KWH and increased 10.1 percent in 2002 due to the effect of the       $65 million of additional capacity expense associated warmer weather. Commercial and industrial KWH sales           with new purchased power agreements (PPAs) between in 2002 increased 1.7 percent and 1.5 percent,                the Company and Southern Power that went into effect respectively, due to corresponding increases of 2.6           in June 2004 and June 2003. Purchased power expense percent and 2.4 percent, respectively, in customers.          increased $92 million (13.3 percent) in 2003 primarily Retail sales growth assuming normal weather is                due to $75 million of additional capacity expense expected to be 1.9 percent on average from 2005 to            associated with new PPAs between the Company and 2009.                                                         Southern Power that went into effect in 2003 and 2002.
Purchased power expense decreased $87 million (11.2 Expenses                                                      percent) in 2002 primarily due to fluctuations in off-system energy purchases used to meet off-system sales Fuel costs constitute the single largest expense for the      commitments. The 2002 decrease in energy purchases Company. The mix of fuel sources for generation of            was partially offset by a $43 million increase in capacity electricity is determined primarily by system load, the       expense associated with new PPAs between the unit cost of fuel consumed, and the availability of hydro     Company and Southern Power.
and nuclear generating units. The amount and sources of generation, the average cost of fuel per net KWH 8

MANAGEMENT'S DISCUSSION AND ANALYSIS                       (continued)
Georgia Power Company 2004 Annual Report A significant upward trend in the cost of coal and                    Taxes other than income taxes increased $15 million natural gas has emerged since 2003, and volatility in                 (7.0 percent) in 2004 due to higher municipal gross these markets is expected to continue. Increased coal                 receipts taxes associated with increased operating prices have been influenced by a worldwide increase                   revenues. Taxes other than income taxes increased $ 11 in demand as a result of rapid economic growth in                     million (5.4 percent) in 2003 due mainly to a favorable China as well as by increases in mining costs. Higher                 true-up of state property tax valuations in 2002. Taxes natural gas prices in the United States are the result of             other than income taxes remained relatively constant in slightly lower gas supplies despite increased drilling                2002.
activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response; however, the impact of                          Allowance for equity funds used during construction this price volatility may be reduced by imports of                    increased $15.9 million in 2004 primarily due to the natural gas and liquefied natural gas. Fuel expenses                  Company's acquisition of the Plant McIntosh combined generally do not affect net income, since they are                    cycle Units 10 and 11 construction project from offset by fuel revenues under the Company's fuel cost                 Southern Power. See FUTURE EARNINGS recovery provisions.                                                  POTENIAL - "FERC and Georgia PSC Matters" and Note 3 to the financial statements under "Retail Rate In 2004, other operation and maintenance expenses                Orders" and "Plant McIntosh Construction Project" for increased $153 million (12.3 percent) due to the timing               additional information.
of generating plant maintenance of $39 million and transmission and distribution maintenance of $39                            Interest income decreased $9 million in 2004 and million. Increased employee benefit expense of $30                     increased $12 million in 2003 when compared to the million related to pension and medical benefits and                    prior year primarily due to interest on a favorable higher workers compensation expense of $8 million also                 income tax settlement of $14.5 million in 2003. Interest contributed to the increase. In 2003, other operation and              income remained relatively constant in 2002.
maintenance expenses decreased $78 million (5.9 percent) due to the timing of generating plant                              Interest expense remained relatively constant in maintenance of $46 million and transmission and                        2004. Interest expense increased in 2003 primarily due distribution maintenance of $8 million and lower                       to an increase in senior notes outstanding that was severance costs of $8 million. In 2002, other operation                partially offset by a reduction in short-term debt and maintenance expenses increased $85 million (6.8                    outstanding. Interest expense decreased in 2002 percent) due to the timing of generating plant                         primarily due to lower interest rates that offset new maintenance of $44 million and transmission                            financing costs. The Company refinanced or retired maintenance of $17 million and increased property                      $400 million, $665 million, and $929 million of insurance expense of $5 million.                                       securities in 2004, 2003, and 2002, respectively. Interest capitalized increased in 2004 due to the Plant McIntosh Depreciation and amortization decreased $74 million               construction project referenced above and decreased in and $54 million in 2004 and 2003, respectively,                        2003 and 2002 due to the transfer of three generation primarily as a result of the amortization of a regulatory             projects to Southern Power in 2002 and 2001. See Note liability related to the inclusion of new certified PPAs in            3 to the financial statements under "Retail Rate Orders" retail rates on a levelized basis as ordered by the Georgia            and "Plant McIntosh Construction Project" for additional PSC. Depreciation and amortization decreased $197                      information regarding the Plant McIntosh construction million in 2002 primarily as a result of discontinuing                project.
accelerated depreciation, beginning amortization of the regulatory liability for accelerated cost recovery, and                    Other income and (expense), net decreased in 2004 lowering the composite depreciation rates as part of the              primarily due to the $13 million disallowance of Plant 2001 Retail Rate Plan. See Note 3 to the financial                    McIntosh construction costs pursuant to a Georgia PSC statements under "Retail Rate Orders" for additional                  order issued on December 21, 2004 (2004 Retail Rate information.                                                          Plan), partially offset by a $7.5 million decrease in donations and $3.4 million in increased income from a customer pricing program. See Note 3 to the financial 9

MANAGEMENT'S DISCUSSION AND ANALYSIS                          (continued)
Georgia Power Company 2004 Annual Report statements under "Retail Rate Orders" and "Plant                          factors that affect the opportunities, challenges, and risks McIntosh Construction Project" for additional                             of the Company's business of selling electricity. These information on the disallowance.                                          factors include the ability to maintain a stable regulatory environment, to recover costs related to growing Effects of Inflation                                                      demand, to achieve energy sales growth while containing costs, and to meet increasingly stringent The Company is subject to rate regulation that is based                   environmental standards. Future earnings in the near on the recovery of historical costs. In addition, the                     term will depend, in part, upon growth in energy sales income tax laws are also based on historical costs.                       which is subject to a number of factors. These factors Therefore, inflation creates an economic loss because the                 include weather, competition, new energy contracts with Company is recovering its costs of investments in dollars                 neighboring utilities, energy conservation practiced by that have less purchasing power. While the inflation rate                 customers, the price of electricity, the price elasticity of has been relatively low in recent years, it continues to                  demand, and the rate of economic growth in the service have an adverse effect on the Company because of the                      area.
large investment in utility plant with long economic lives. Conventional accounting for historical cost does                        Since 2001, merchant energy companies and not recognize this economic loss nor the partially                        traditional electric utilities with significant energy offsetting gain that arises through financing facilities                  marketing and trading activities have come under with fixed-money obligations such as long-term debt,                      severe financial pressures. Many of these companies preferred stock, and preferred securities. Any                            have completely exited or drastically reduced all recognition of inflation by regulatory authorities is                     energy marketing and trading activities and sold reflected in the rate of return allowed in the Company's                  foreign and domestic electric infrastructure assets.
The Company has not experienced any material approved electric rates.
adverse financial impact regarding its limited energy trading operations through Southern Company FUTURE EARNINGS POTENTIAL Services, Inc. (SCS).
General EnvironmentalMatters The Company operates as a vertically integrated New Source Review Actions company providing electricity to retail customers within its traditional service territory located within the State of In November 1999, the Environmental Protection Georgia and to wholesale customers in the southeastern Agency (EPA) brought a civil action in the U.S District United States. Prices for electricity provided by the                     Court for the Northern District of Georgia against the Company to retail customers are set by the Georgia PSC Company, alleging that the Company had violated the under cost-based regulatory principles. Prices for New Source Review (NSR) provisions of the Clean Air electricity relating to jointly owned generating facilities, Act and related state laws with respect to coal-fired interconnecting transmission lines, and the exchange of generating facilities at plants Bowen and Scherer. The electric power are set by the FERC. Retail rates and civil action requests penalties and injunctive relief, revenues are reviewed and adjusted periodically within including an order requiring the installation of the best certain limitations based on earned ROE. See available control technology at the affected units. The ACCOUNTING POLICIES - "Application of Critical action against the Company was effectively stayed in the Accounting Policies and Estimates - Electric Utility spring of 2001 pending the appeal of a similar NSR Regulation" herein and Note 3 to the financial action against the Tennessee Valley Authority (TVA) statements under "Retail Rate Orders" and "Market-before the U.S. Court of Appeals for the Eleventh Based Rate Authority" for additional information about Circuit. In June 2003, the Court of Appeals issued its this and other regulatory matters.
ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the case pending The results of operations for the past three years are against the Company. At this time, no party to the case not necessarily indicative of future earnings potential.
against the Company has sought to reopen the case, The level of future earnings depends on numerous which remains administratively closed in the U.S.
10

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2004 Annual Report District Court for the Northern District of Georgia. See        Court ruling in favor of the Company in part and the Note 3 to the financial statements under "New Source            plaintiffs in part. The Company has filed a petition for Review Actions" for additional information.                     review of the decision with the U.S. Court of Appeals for the Eleventh Circuit. The district court case has been The Company believes that it complied with                 administratively closed pending that appeal. If applicable laws and the EPA regulations and                     necessary, the district court will hold a separate remedy interpretations in effect at the time the work in question      trial which will address civil penalties and possible took place. The Clean Air Act authorizes maximum                injunctive relief requested by the plaintiffs. See Note 3 civil penalties of $25,000 to $32,500 per day, per              to the financial statements under "Plant Wansley violation at each generating unit, depending on the date        Environmental Litigation" for additional information.
of the alleged violation. An adverse outcome in this            The ultimate outcome of this matter cannot currently be case could require substantial capital expenditures that        determined; however, an adverse outcome could result in cannot be determined at this time and could possibly            substantial capital expenditures that cannot be require payment of substantial penalties. This could            determined at this time and could possibly require affect future results of operations, cash flows, and            payment of substantial penalties. This could affect possibly financial condition if such costs are not              future results of operations, cash flows, and possibly recovered through regulated rates.                              financial condition if such costs are not recovered through regulated rates.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the         CarbonDioxide Litigation Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of         On July 21, 2004, attorneys general from eight states, calculating emissions increases. The October 2003               each outside of Southern Company's service territory, regulations clarified the scope of the existing Routine         and the corporation counsel of New York filed a Maintenance, Repair, and Replacement (RMRR)                     complaint in the U.S. District Court for the Southern exclusion. A coalition of states and environmental              District of New York against Southern Company and organizations has filed petitions for review of these           four other electric power companies. A nearly identical revisions with the U.S. Court of Appeals for the District       complaint was filed by three environmental groups in the of Columbia Circuit. The October 2003 RMRR rules                same court. The complaints allege that the companies' have been stayed by the Court of Appeals pending its            emissions of carbon dioxide, a greenhouse gas, review of the rules. In any event, the final regulations        contribute to global warming, which the plaintiffs assert must also be adopted by the State of Georgia in order to        is a public nuisance. Under common law public and apply to the Company's facilities. The effect of these          private nuisance theories, the plaintiffs seek a judicial final regulations, related legal challenges, and potential      order (1) holding each defendant jointly and severally rulemakings by the State of Georgia cannot be                   liable for creating, contributing to, and/or maintaining, determined at this time.                                        global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce Plant Wansley Environmental Litigation                          those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested On December 30, 2002, the Sierra Club, Physicians for           that damages be awarded in connection with their Social Responsibility, Georgia Forestwatch, and one             claims. Southern Company believes these claims are individual filed a civil suit in the U.S. District Court for    without merit and notes that the complaint cites no the Northern District of Georgia against the Company            statutory or regulatory basis for the claims. Southern for alleged violations of the Clean Air Act at four of the      Company and the other defendants have filed motions to units at Plant Wansley. The civil action requests               dismiss both lawsuits. Southern Company intends to injunctive and declaratory relief, civil penalties, a           vigorously defend against these claims. While the supplemental environmental project, and attorneys' fees.        outcome of these matters cannot be determined at this The Clean Air Act authorizes civil penalties of up to           time, an adverse judgment could result in substantial
$27,500 per day, per violation at each generating unit.         capital expenditures.
The liability phase of the case has concluded with the 11

MANAGEMENT'S DISCUSSION AND ANALYSIS                       (continued)
Georgia Power Company 2004 Annual Report Environmental Statutes and Regulations                                 the EPA announced that it would stay implementation of the rule as it relates to Georgia, while it initiates The Company's operations are subject to extensive                      rulemakings to address issues raised in a petition for regulation by state and federal environmental agencies                 reconsideration filed by a coalition of Georgia industries.
under a variety of statutes and regulations governing                  The impact of the nitrogen oxide reduction rules will environmental media, including air, water, and land                    depend on the outcome of the petition for resources. Compliance with these environmental                         reconsideration and/or any subsequent development and requirements involves significant capital and operating                approval of Georgia's state implementation plan and costs, a major portion of which is expected to be                      cannot be determined at this time.
recovered through existing ratemaking provisions.
Environmental costs that are known and estimable at this                    In September 2003, the EPA reclassified the Atlanta time are included in capital expenditures under                        area from a "serious" to a "severe" nonattainment area FINANCIAL CONDITION AND LIQUIDITY -                                    for the one-hour ozone standard effective January 1, "Capital Requirements and Contractual Obligations"                     2004. However, based on the last three years of data, the herein. There is no assurance, however, that all such                  State of Georgia believes that the Atlanta area has costs will, in fact, be recovered.                                     attained the one-hour standard and is in the process of applying for redesignation from the EPA.
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant                  In July 1997, the EPA revised the national ambient focus for the Company. The Title IV acid rain                          air quality standards for ozone and particulate matter.
provisions of the Clean Air Act, for example, required                 These revisions made the standards significantly more significant reductions in sulfur dioxide and nitrogen                  stringent and included development of an eight-hour oxide emissions and resulted in total construction                     ozone standard, as opposed to the previous one-hour expenditures of approximately $206 million through                     ozone standard. In the subsequent litigation of these 2000. Some of these previous expenditures also assisted                standards, the U.S. Supreme Court found the EPA's the Company in complying with nitrogen oxide emission                  implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for reduction requirements under Title I of the Clean Air further rulemaking. During 2003, the EPA proposed Act, which were designed to address one-hour ozone                     implementation rules designed to address the court's nonattainment problems in Atlanta, Georgia. The State                  concerns. On April 30, 2004, the EPA published its of Georgia adopted regulations that required additional                eight-hour ozone nonattainment designations and a nitrogen oxide emission reductions from May through                    portion of the rules implementing the new eight-hour September of each year at plants in and/or near                        standard. Areas within the Company's service territory nonattainment areas. Seven generating plants in the                    that have been designated as nonattainment under the Atlanta area are currently subject to those requirements,              eight-hour ozone standard include Macon, Georgia and a the most recent of which went into effect in 2003.                     20-county area within metropolitan Atlanta. Under the Construction expenditures for compliance with the                      implementation provisions of the new rule, the EPA nitrogen oxide emission reduction requirements totaled                 announced that the one-hour ozone standard will be
$687.2 million through 2004, with an additional $6                     revoked on June 15, 2005, and that areas classified as million committed through 2007.                                        "severe" nonattainment areas under the one-hour standard, such as Atlanta, will not be required to impose To help attain the one-hour ozone standard, the EPA              emissions fees if those areas fail to come into attainment issued regional nitrogen oxide reduction rules in 1998.                with the one-hour standard. With respect to the eight-Those rules required 21 states, including Georgia, to                  hour nonattainment areas, state implementation plans, reduce and cap nitrogen oxide emissions from power                     including new emission control regulations necessary to plants and other large industrial sources. As a result of              bring those areas into attainment, could be required as litigation challenging the rule, the courts required the              early as 2007. These state implementation plans could EPA to complete a separate rulemaking before the                      require reductions in nitrogen oxide emissions from requirements could be applied in Georgia. In April                     power plants. The impact of the eight-hour designations and the new standard will depend on the development 2004, the EPA published final regional nitrogen oxide and implementation of applicable state implementation reduction rules applicable to Georgia, specifying a May                plans and therefore cannot be determined at this time.
1, 2007 compliance date. However, in October 2004, 12

NMANAGEMENT'S DISCUSSION AND ANALYSIS                      (continued)
Georgia Power Company 2004 Annual Report On December 17, 2004, the EPA issued its final                    that make progress toward remedying current visibility "nonattainment" designations for the fine particulate                  impairment in certain natural areas. The Company has a national ambient air quality standard. Several areas                   number of plants that could be subject to these rules.
within the Company's service territory in Georgia were                 The EPA's Regional Haze program calls for states to included in the EPA's final particulate matter                         submit implementation plans in 2008 that contain designations. The EPA plans to propose a fine                          emission reduction strategies for implementing BART particulate matter implementation rule in 2005 and                     and for achieving sufficient progress toward the Clean finalize the implementation rule in 2006. State                        Air Act's visibility improvement goal. In response to implementation plans addressing the nonattainment                      litigation, the EPA proposed revised rules in May 2004, designations may be required by 2008 and could require                 which it plans to finalize in April 2005. The impact of reductions in sulfur dioxide emissions and further                     these regulations will depend on the promulgation of reductions in nitrogen oxide emissions from power                      final rules and implementation of those rules by the plants. The impact of the fine particulate designations                states and, therefore, it is not possible to determine the will depend on the development and implementation of                   effect of these rules on the Company at this time.
applicable state implementation plans and therefore cannot be determined at this time.                                          In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility In January 2004, the EPA issued a proposed Clean                  boilers. The proposal solicits comments on two possible Air Interstate Rule (CAIR) to address interstate transport             approaches for the new regulations - a Maximum of ozone and fine particles. This proposed rule would                  Achievable Control Technology approach and a cap-require additional year-round sulfur dioxide and nitrogen              and-trade approach. Either approach would require oxide emission reductions from power plants in the                     significant reductions in mercury emissions from eastern United States in two phases - in 2010 and 2015.                Company facilities. The regulations are scheduled to be The EPA currently plans to finalize this rule in 2005. If              finalized by March 2005, and compliance could be finalized, the rule could modify or supplant other state               required as early as 2008. Because the regulations have requirements for attainment of the fine particulate matter             not been finalized, the impact on the Company cannot be standard, the eight-hour ozone standard, and other air                 determined at this time.
quality regulations. The impact of this rule on the Company will depend upon the specific requirements of Major bills to amend the Clean Air Act to impose the final rule and cannot be determined at this time.
more stringent emissions limitations on power plants, including the Bush Administration's Clear Skies Act, The Company has developed and maintains an                         have been proposed in 2005. The Clear Skies Act is environmental compliance strategy for the installation of              expected to further limit power plant emissions of sulfur additional control technologies and the purchase of                   dioxide, nitrogen oxides, and mercury and to supplement emission allowances to assure continued compliance                     the proposed CAIR and mercury regulatory programs.
with current sulfur dioxide and nitrogen oxide emission                Other proposals have also been introduced to limit regulations. Additional expenses associated with these                 emissions of carbon dioxide. The cost impacts of such regulations are anticipated to be incurred each year to                legislation would depend upon the specific requirements maintain current and future compliance. Because the                    enacted and cannot be determined at this time.
Company's compliance strategy is impacted by factors such as changes to existing environmental laws and                         Under the Clean Water Act, the EPA has been regulations, increases in the cost of emissions                       developing new rules aimed at reducing impingement and allowances, and any changes in the Company's fuel mix,                entrainment of fish and fish larvae at power plants' cooling future environmental compliance costs cannot be                       water intake structures. In July 2004, the EPA published determined at this time.                                              final rules that will require biological studies and, perhaps, retrofits to some intake structures at existing power plants.
Further reductions in sulfur dioxide and nitrogen                 The impact of these new rules will depend on the results of oxides could also be required under the EPA's Regional                studies and analyses performed as part of the rules' Haze rules. The Regional Haze rules require states to                  implementation and the actual limits established by the establish Best Available Retrofit Technology (BART)                   regulatory agencies.
standards for certain sources that contribute to regional haze and to implement emission reduction requirements 13

MANAGEMENT'S DISCUSSION AND ANALYSIS                          (continued)
Georgia Power Company 2004 Annual Report The Company is installing cooling towers at additional              under Climate VISION. Because efforts under this facilities under the Clean Water Act to cool water prior to              voluntary program are just beginning, the impact of this discharge. Near Atlanta, a cooling tower for one plant was               program on the Company cannot be determined at this completed in 2004 with two others scheduled for                          time.
completion in 2008. The total estimated cost of these projects is $248 million, with $170 million remaining to be              Environmental Remediation Reserves spent Also, the Company is conducting a study of the aquatic environment at another facility to determine if                  The Company must comply with other environmental further thermal controls are necessary at that plant.                     laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under Several major pieces of environmental legislation                   these various laws and regulations, the Company could are periodically considered for reauthorization or                        incur substantial costs to clean up properties. The amendment by Congress. These include: the Clean Air                      Company conducts studies to determine the extent of Act; the Clean Water Act; the Comprehensive                               any required cleanup and has recognized in its financial Environmental Response, Compensation, and Liability                       statements the costs to clean up and monitor known Act; the Resource Conservation and Recovery Act; the                     sites. Amounts for cleanup and ongoing monitoring Toxic Substances Control Act; the Emergency Planning                     costs were not material for any year presented. The
& Community Right-to-Know Act; and the Endangered                        Company may be liable for some or all required cleanup Species Act. Compliance with possible additional                         costs for additional sites that may require environmental federal or state legislation or regulations related to global            remediation. See Note 3 to the financial statements climate change or other environmental and health                         under "Environmental Remediation" for additional concerns could also significantly affect the Company.                    information.
The impact of any new legislation, changes to existing legislation, or environmental regulations could affect                         Under Georgia PSC ratemaking provisions, $22 many areas of the Company's operations. The full                         million has been deferred in a regulatory liability impact of any such changes cannot, however, be                           account for use in meeting future environmental determined at this time.                                                 remediation costs of the Company. Under the 2004 Retail Rate Plan, this regulatory liability will be Global Climate Issues                                                    amortized as a credit to expense over a three-year period beginning January 1, 2005. However, the Georgia PSC Domestic efforts to limit greenhouse gas emissions have                  also approved an annual environmental accrual of $5.4 been spurred by international discussions surrounding million. Environmental remediation expenditures will the Framework Convention on Climate Change -- and specifically the Kyoto Protocol -- which proposes                        be charged against the reserve as they are incurred. The constraints on the emissions of greenhouse gases for a                   annual accrual amount will be reviewed and adjusted in group of industrialized countries. The Bush                               future regulatory proceedings.
Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide                         FERC and GeorgiaPSCMatters reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. - the                     Transmission ratio of greenhouse gas emissions to the value of U.S.
economic output -- by 18 percent by 2012. A year later,                  In December 1999, the FERC issued its final rule on the Department of Energy (DOE) announced the Climate                     Regional Transmission Organizations (RTOs). Since VISION program to support this goal. Energy-intensive                    that time, there have been a number of additional industries, including electricity generation, are the initial            proceedings at the FERC designed to encourage further focus of this program. Southern Company is leading the                   voluntary formation of RTOs or to mandate their development of a voluntary electric utility sector climate               formation. However, at the current time, there are no change initiative in partnership with the government.                    active proceedings that would require the Company to The utility sector has pledged to reduce its greenhouse                  participate in an RTO. Current FERC efforts that may gas emissions rate by 3 to 5 percent over the next decade                potentially change the regulatory and/or operational and, on December 13, 2004, signed a memorandum of                        structure of transmission include rules related to the understanding with the DOE initiating this program standardization of generation interconnection, as well as 14

MANAGEMENT'S DISCUSSION AND ANALYSIS                     (continued)
Georgia Power Company 2004 Annual Report an inquiry into, among other things, market power by                 of certain mitigation measures. In April 2004, the FERC vertically integrated utilities. See "Generation                     issued an order that abandoned the SMA test and Interconnection Agreements" and "Market-Based Rate                   adopted a new interim analysis for measuring generation Authority" herein for additional information. The final              market power. This new interim approach requires outcome of these proceedings cannot now be                           utilities to submit a pivotal supplier screen and a determined. However, the Company's financial                         wholesale market share screen. If the applicant does not condition, results of operations, and cash flows could be            pass both screens, there will be a rebuttable presumption adversely affected by future changes in the federal                  regarding generation market power. The FERC's order also sets forth procedures for rebutting these regulatory or operational structure of transmission.
presumptions and addresses mitigation measures for those entities that are found to have market power. In GenerationInterconnectionAgreements                                 the absence of specific mitigation measures, the order includes several cost-based mitigation measures that In July 2003, the FERC issued its final rule on the                  would apply by default. The FERC also initiated a new standardization of generation interconnection                        rulemaking proceeding that, among other things, will agreements and procedures (Order 2003). Order 2003                   adopt a final methodology for assessing generation shifts much of the financial burden of new                          market power.
transmission investment from the generator to the transmission provider. The FERC has indicated that                         In July 2004, the FERC denied Southern Order 2003, which was effective January 20, 2004, is                 Company's request for rehearing, along with a to be applied prospectively to interconnection                       number of others, and reaffirmed the interim tests that agreements. Subsidiaries of Tenaska, Inc., as                        it adopted in April 2004. In August 2004, Southern counterparties to previously executed interconnection                Company submitted a filing to the FERC which agreements with the Company and another Southern                     included results showing that Southern Company Company subsidiary, have filed complaints at the                     passed the pivotal supplier screen for all markets and FERC requesting that the FERC modify the                             the wholesale market share screen for all markets agreements and that the Company refund a total of                    except the Southern Company retail service territory.
$7.9 million previously paid for interconnection                     Southern Company also submitted other analyses to facilities, with interest. The Company has opposed                   demonstrate that it lacks generation market power.
such relief and the proceedings are still pending. The               On December 17, 2004, the FERC initiated a impact of Order 2003 and its subsequent rehearings                   proceeding to assess Southern Company's generation on the Company and the final results of these matters                dominance within its retail service territory. The cannot be determined at this time.                                   ability to charge market-based rates in other markets is not at issue. As directed by this order, on February Market-BasedRate Authority                                           15, 2005, Southern Company submitted additional information related to generation dominance in its The Company has authorization from the FERC to sell                  retail service territory. Any new market-based rate power to nonaffiliates at market-based prices. Through               transactions in the Southern Company retail service SCS, as agent, the Company also has FERC authority to                territory entered into after February 27, 2005 will be make short-term opportunity sales at market rates.                   subject to refund to the level of the default cost-based Specific FERC approval must be obtained with respect                 rates, pending the outcome of the proceeding.
to a market-based contract with an affiliate. In                     Southern Company, along with other utilities, has also November 2001, the FERC modified the test it uses to                 filed an appeal of the FERC's April and July 2004 consider utilities' applications to charge market-based              orders with the U.S. Court of Appeals for the District rates and adopted a new test called the Supply Margin                of Columbia Circuit. The FERC has asked the court Assessment (SMA). The FERC applied the SMA to                        to dismiss the appeal on the grounds that it is several utilities, including Southern Company, the retail            premature.
operating companies, and Southern Power, and found Southern Company, and others to be "pivotal suppliers"                    In the event that the FERC's default mitigation in their retail service territories and ordered the                  measures are ultimately applied, the Company may be implementation of several mitigation measures.                       required to charge cost-based rates for certain Southern Company and others sought rehearing of the                  wholesale sales in the Southern Company retail FERC order, and the FERC delayed the implementation                  service territory, which may be lower than negotiated 15

MANAGEMENT'S DISCUSSION AND ANALYSIS                    (continued)
Georgia Power Company 2004 Annual Report market-based rates. The final outcome of this matter                Savannah Electric requested the Georgia PSC to will depend on the form in which the final                         direct them to acquire the McIntosh construction methodology for assessing generation market power                  project. The Georgia PSC issued such an order and and mitigation rules may be ultimately adopted and                 the transfer occurred on May 24, 2004 at a total cost cannot be determined at this time.                                  of approximately $415 million, including $14 million of transmission interconnection facilities.
Retail Rate Case                                                    Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing On December 21, 2004, the Georgia PSC approved                      FERC proceedings. In August 2004, the FERC issued the 2004 Retail Rate Plan for the three-year period                 a notice accepting the request to withdraw the PPAs ending December 31, 2007. Under the terms of the                    and permitting such request to become effective by 2004 Retail Rate Plan, earnings will be evaluated                   operation of law. However, the FERC made no annually against a retail ROE range of 10.25 percent                determination on what additional steps may need to to 12.25 percent. Two-thirds of any earnings above                  be taken with respect to testimony provided in the 12.25 percent will be applied to rate refunds, with the             proceedings. The ultimate outcome of any additional remaining one-third retained by the Company. Retail                 FERC action cannot now be determined at this time.
rates will be increased by approximately $194 million and customer fees will be increased by approximately                     As directed by the Georgia PSC order, in June
$9 million effective January 1, 2005 to cover the                   2004, the Company and Savannah Electric filed an higher costs of purchased power; operating and                      application to amend the resource certificate granted maintenance expenses; environmental compliance;                     by the Georgia PSC in 2002 to change the character and continued investment in new generation,                         of the resource from a PPA to a self-owned, rate transmission and distribution facilities to support                 based asset and to describe the approximate growth and ensure reliability.                                      construction schedule and the proposed rate base treatment. In connection with the 2004 Retail Rate The Company will not file for a general base rate             Plan, the Georgia PSC approved the transfer of the increase unless its projected retail ROE falls below                Plant McIntosh construction project at a total fair 10.25 percent. The Company is required to file a general           market value of approximately $385 million. This rate case by July 1, 2007, in response to which the                 value reflects an approximate $16 million Georgia PSC would be expected to determine whether                  disallowance, of which $13 million is attributable to the Company, and reduced the Company's net income the 2004 Retail Rate Plan should be continued, modified by approximately $8 million. The Georgia PSC also or discontinued. See Note 3 to the financial statements             certified a total completion cost of $547 million for under "Retail Rate Orders" for additional information.              the project. The amount of the disallowance will be adjusted accordingly based on the actual completion Plant McIntosh ConstructionProject                                  cost of the project. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact will In December 2002 after a competitive bidding                       be reflected in the Company's rates evenly over the process, the Georgia PSC certified PPAs between                     three years ending 2007. See Note 3 to the financial Southern Power and the Company and Savannah                        statements under "Retail Rate Orders" and "Plant Electric and Power Company (Savannah Electric) for                 McIntosh Construction Project" for additional capacity from Plant McIntosh Units 10 and 11,                      information.
construction of which is scheduled to be completed in June 2005. In April 2003, Southern Power applied Retail Fuel Cost Recovery for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be              The Company has established fuel cost recovery rates held. Intervenors opposed the FERC's acceptance of                 approved by the Georgia PSC. In recent months, the the PPAs, alleging that they did not meet the                      Company has experienced higher than expected fuel applicable standards for market-based rates between                costs for coal and gas. Those higher fuel costs have affiliates. To ensure the timely completion of the                 increased the under recovered fuel costs included in the Plant McIntosh construction project and the                        balance sheets herein. On February 18, 2005, the availability of the units in the summer of 2005 for                Company filed a request with the Georgia PSC for a fuel their retail customers, in May 2004, the Company and               cost recovery rate increase. In the ordinary course, these 16

MANAGEMENT'S DISCUSSION AND ANALYSIS                        (continued)
Georgia Power Company 2004 Annual Report new rates will be effective June 1, 2005 following a                   to the pension plan. The decline in pension income is hearing before and approval by the Georgia PSC. In its                 expected to continue and to become an expense by as filing, the Company asked that the Georgia PSC accept                 early as 2007. Postretirement benefit costs for the the new rate, effective April 1, 2005, prior to a formal               Company were $44 million, $41 million and $43 million hearing on the Company's request. This action, if taken                in 2004, 2003, and 2002, respectively, and are expected by the Georgia PSC, would serve to mitigate expected                   to trend upward. A portion of pension income and increases in the under recovered balance during April                 postretirement benefit costs is capitalized based on and May, but will not preclude the Georgia PSC from                   construction-related labor charges. For the Company, subsequently adjusting the rates. The requested                       pension income or expense and postretirement benefit increase, representing an annual increase in revenues of               costs are a component of the regulated rates and approximately 11.7 percent, will allow for the recovery                generally do not have a long-term effect on net income.
of fuel costs based on an estimate of future fuel costs, as            For more information regarding pension and well as the collection of the existing under recovery of               postretirement benefits, see Note 2 to the financial fuel costs. The Company's under recovered fuel costs as                statements.
of January 31, 2005 totaled $390 million. The Georgia PSC will examine the Company's fuel expenditures and                        On October 22, 2004, President Bush signed the determine whether the proposed fuel cost recovery rate                 American Jobs Creation Act of 2004 (Jobs Act) into law.
is just and reasonable before issuing its decision in May              The Jobs Act includes a provision that allows a 2005. The final outcome of the filing cannot be                        generation tax deduction for utilities. The Company is determined at this time. See Note 3 to the financial                   currently assessing the impact of the Jobs Act, including statements under "Fuel Cost Recovery" for further                      this deduction, as well as the related regulatory information regarding this filing.                                     treatment, on its taxable income. However, the Company currently does not expect the Jobs Act to have Storm Damage Cost Recovery                                             a material impact on its financial statements.
During the month of September 2004, the Company's                           The Company is involved in various other matters service territory was impacted by Hurricanes Frances,                  being litigated, regulatory matters, and related issues that Ivan and Jeanne. The Company maintains a reserve                       could affect future earnings. See Note 3 to the financial for property damage to cover the cost of damages                       statements for information regarding material issues.
from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated                   ACCOUNTING POLICIES by the Georgia PSC. The total amount of damage related to these hurricanes was estimated to be                        Application of Critical Accounting Policies and approximately $15 million and was charged to the                       Estimates storm damage reserve in 2004. These costs are expected to be recovered through regular monthly                       The Company prepares its financial statements in accruals which total $6.3 million annually under the                   accordance with accounting principles generally 2004 Retail Rate Plan. See Note 3 to the financial                     accepted in the United States. Significant accounting statements under "Retail Rate Orders" for additional                   policies are described in Note I to the financial information.                                                           statements. In the application of these policies, certain estimates are made that may have a material Other Matters                                                          impact on the Company's results of operations and related disclosures. Different assumptions and In accordance with Financial Accounting Standards                      measurements could produce estimates that are Board (FASB) Statement No. 87, Employers'                              significantly different from those recorded in the Accounting for Pensions, the Company recorded non-                     financial statements. Southern Company senior cash pension income, before tax, of approximately $35                  management has discussed the development and million, $54 million, and $59 million in 2004, 2003, and               selection of the critical accounting policies and estimates described below with the Audit Committee 2002, respectively. Future pension income is dependent of Southern Company's Board of Directors.
on several factors including trust earnings and changes 17

MANAGENIENT'S DISCUSSION AND ANALYSIS                      (continued)
Georgia Power Company 2004 Annual Report Electric Utility Regulation                                           principles. The adequacy of reserves can be significantly affected by external events or conditions The Company is subject to retail regulation by the                    that can be unpredictable; thus, the ultimate outcome Georgia PSC and wholesale regulation by the FERC.                     of such matters could materially affect the Company's These regulatory agencies set the rates the Company                    financial statements. These events or conditions is permitted to charge customers based on allowable                    include the following:
costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of
* Changes in existing state or federal regulation by Certain Types of Regulation, which requires the                            governmental authorities having jurisdiction over financial statements to reflect the effects of rate                        air quality, water quality, control of toxic regulation. Through the ratemaking process, the                            substances, hazardous and solid wastes, and other regulators may require the inclusion of costs or                           environmental matters.
revenues in periods different than when they would be
* Changes in existing income tax regulations or recognized by a non-regulated company. This                                changes in Internal Revenue Service treatment may result in the deferral of expenses and                       interpretations of existing regulations.
the recording of related regulatory assets based on
* Identification of additional sites that require anticipated future recovery through rates or the                           environmental remediation or the filing of other deferral of gains or creation of liabilities and the                       complaints in which the Company may be asserted recording of related regulatory liabilities. The                           to be a potentially responsible party.
application of Statement No. 71 has a further effect on
* Identification and evaluation of other potential the Company's financial statements as a result of the                      lawsuits or complaints in which the Company may estimates of allowable costs used in the ratemaking                        be named as a defendant.
process. These estimates may differ from those
* Resolution or progression of existing matters actually incurred by the Company; therefore, the                           through the legislative process, the court systems, accounting estimates inherent in specific costs such as                    or the EPA.
depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct                      Unbilled Revenues impact on the Company's results of operations than they would on a non-regulated company.                                Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the As reflected in Note I to the financial statements,              determination of KWH sales to individual customers is significant regulatory assets and liabilities have been               based on the reading of their meters, which is performed recorded. Management reviews the ultimate                             on a systematic basis throughout the month. At the end recoverability of these regulatory assets and liabilities             of each month, amounts of electricity delivered to based on applicable regulatory guidelines. However,                   customers, but not yet metered and billed, are estimated.
adverse legislative, judicial or regulatory actions                   Components of the unbilled revenue estimates include could materially impact the amounts of such total KWH territorial supply, total KWH billed, regulatory assets and liabilities and could adversely impact the Company's financial statements.                            estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a Contingent Obligations                                                number of factors including weather, generation patterns, power delivery volume and other power The Company is subject to a number of federal and                     delivery operational constraints. These factors can be state laws and regulations, as well as other factors and               unpredictable and can vary from historical trends. As a conditions that potentially subject it to environmental,              result, the overall estimate of unbilled revenues could be litigation, income tax, and other risks. See FUTURE                    significantly affected, which could have a material EARNINGS POTENTIAL herein and Note 3 to the                            impact on the Company's results of operations.
financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting 18

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2004 Annual Report New Accounting Standards                                   Note I to the financial statements under "Stock Options."
On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, "Consolidation              See FUTURE EARNINGS POTENTIAL -
of Variable Interest Entities," which requires the         "Other Matters" herein for information regarding the primary beneficiary of a variable interest entity to       adoption of new tax legislation. In December 2004, consolidate the related assets and liabilities. The        the FASB issued FSP 109-1, Application of FASB adoption of FASB Interpretation No. 46R had no             Statement No. 109, Accounting for Income Taxes, to impact on the Company's net income. However, as a          the Tax Deduction on Qualified Production Activities result of the adoption, the Company deconsolidated         provided by the American Jobs Creation Act of 2004, certain wholly-owned trusts established to issue           which requires that the generation deduction be preferred securities since the Company did not meet        accounted for as a special tax deduction rather than as the definition of primary beneficiary established by       a tax rate reduction. The Company is currently FASB Interpretation No. 46R. See Note 1 to the             assessing the Jobs Act and this pronouncement, as financial statements under "Variable Interest Entities"    well as the related regulatory treatment, but currently for additional information.                                does not expect a material impact on the Company's financial statements.
In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP)            FINANCIAL CONDITION AND LIQUIDITY 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug,                 Overview Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28             Over the last several years, the Company's financial percent prescription drug subsidy for Medicare             condition has remained stable with emphasis on cost eligible retirees. FSP 106-2 requires recognition of        control measures combined with significantly lower the impacts of the Medicare Act in the accumulated         costs of capital, achieved through the refinancing and/or postretirement benefit obligation (APBO) and future        redemption of higher-cost securities. Cash flow from cost of service for postretirement medical plans. The      operations decreased $219 million resulting primarily effect of the subsidy reduced the Company's expenses       from the increase in under recovered deferred fuel costs.
for the six months ended December 31, 2004 by approximately $5 million and is expected to have a               In 2004, gross utility plant additions were $1.1 similar impact on future expenses. The subsidy's           billion. These additions were primarily related to the impact on the postretirement medical plan APBO was construction of Plant McIntosh Units 10 and 11, a reduction of approximately $72 million. However, the ultimate impact on future periods is subject to        transmission and distribution facilities, and the purchase final interpretation of the federal regulations which      of nuclear fuel and equipment to comply with were published on January 21, 2005. See Note 2 to          environmental standards. The majority of funds needed the financial statements under "Postretirement             for gross property additions for the last several years Benefits" for additional information.                      have been provided from operating activities and capital contributions from Southern Company. The statements FASB Statement No. 123R, Share-Based                  of cash flows provide additional details.
Payments, was issued in December 2004. This statement requires that compensation cost relating to           The Company's ratio of common equity to total share-based payment transactions be recognized in          capitalization -- including short-term debt -- was 47.7 financial statements. That cost will be measured           percent in 2004 and 48.3 percent in 2003 and 2002. See based on the grant date fair value of the equity or        Note 6 to the financial statements for additional liability instruments issued. For the Company, this        information.
statement is effective beginning July 1, 2005.
Although the compensation expense calculation              Sources of Capital required under the revised statement differs slightly, the impacts on the financial statements are expected       The Company expects to meet future capital to be similar to the pro forma disclosures included in     requirements primarily using funds generated from operating activities and capital contributions from 19

MANAGEMENT'S DISCUSSION AND ANALYSIS                      (continued)
Georgia Power Company 2004 Annual Report Southern Company and by the issuance of new debt                     are not commingled with proceeds from issuances for securities, term loans, and short-term borrowings. The               the benefits of any other operating company. The type and timing of future financings will depend on                  obligations of each company under these arrangements market conditions and regulatory approval of additional              are several; there is no cross affiliate credit support. As financing authority. Recently, the Company has relied                of December 31, 2004, the Company had outstanding on the issuance of unsecured securities to meet its long-            $208 million of commercial paper and no extendible term external financing requirements.                                commercial notes.
The issuance of securities by the Company is subject                  At the beginning of 2005, the Company had not used to regulatory approval by the Securities and Exchange                any of its available credit arrangements. Bank credit Commission (SEC) under the Public Utility Holding                    arrangements are as follows:
Company Act of 1935, as amended (PUHCA), and by the Georgia PSC. Additionally, with respect to the                                                          Expires public offering of securities, the Company must file                      Total     Unused         2005     2006      2007 registration statements with the SEC under the Securities                                             (in millions)
Act of 1933, as amended (1933 Act). The amounts of                      $773.1     $773.1       $423.1           -    $350 securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the                   The credit arrangements that expire in 2005 allow 1933 Act, are continuously monitored and appropriate                  for the execution of term loans for an additional two-filings are made to ensure flexibility in the capital                year period.
markets.
Financing Activities The Company obtains financing separately without credit support from any affiliate. The Southern                      During 2004, the Company issued $806 million of long-Company system does not maintain a centralized cash or               term debt including long-term debt payable to affiliated money pool. Therefore, funds of the Company are not                  trusts. The issuances were used to refund $400 million commingled with funds of any other company. In                       of long-term debt, as well as to finance the Company's accordance with the PUHCA, most loans between                        purchase of the Plant McIntosh construction project affiliated companies must be approved in advance by the               from Southern Power. The remainder was used to SEC.                                                                 reduce short-term debt and fund the Company's ongoing construction program.
The Company's current liabilities frequently exceed current assets because of the continued use of short-term                  Subsequent to December 31, 2004, the Company debt as a funding source to meet cash needs which can                has issued $250 million of securities with the fluctuate significantly due to the seasonality of the                proceeds used to fund the February 2005 maturity of business.                                                             floating rate senior notes.
To meet short-term cash needs and contingencies,                 Credit Rating Risk the Company had approximately $773.1 million of unused credit arrangements with banks at the beginning                The Company does not have any credit arrangements of 2005. See Note 6 to the financial statements under                 that would require material changes in payment "Bank Credit Arrangements" for additional information.                schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could The Company may also meet short-term cash needs                  require collateral, but not accelerated payment, in the through a Southern Company subsidiary organized to                    event of a credit rating change to BBB- or Baa3 or issue and sell commercial paper and extendible                       below. Generally, collateral may be provided for by a commercial notes at the request and for the benefit of the            Southern Company guaranty, letter of credit or cash.
Company and the other Southern Company operating                      These contracts are primarily for physical electricity companies. Proceeds from such issuances for the benefit              purchases and sales. At December 31, 2004, the of the Company are loaned directly to the Company and                 maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $8 million. The 20

MANAGEMENT'S DISCUSSION AND ANALYSIS                        (continued)
Georgia Power Company 2004 Annual Report maximum potential collateral requirements at a rating                   value of changes in energy-related derivative contracts below BBB- or Baa3 were approximately $247 million.                     and year-end valuations were as follows at December The Company is also party to certain derivative                         31:
agreements that could require collateral and/or accelerated payment in the event of a credit rating                                                              Changes in Fair Value change to below investment grade. These agreements                                                                     2004           2003 are primarily for natural gas price and interest rate risk                                                                   (inmillions) management activities. At December 31, 2004, the                         Contracts beginning of year                    $3.2         $ 0.1 Company had no material exposure related to these                        Contracts realized or settled                 (12.2)          (0.4) agreements.                                                              New contracts at inception Changes in valuation techniques Market Price Risk                                                        Current period changes (a)                      14.8           3.5 Contracts end of year                          $5.8         $ 3.2 Due to cost-based regulations, the Company has limited exposure to market volatility in interest rates,                          (a) Current period changes also include the changes in fair commodity fuel prices and prices of electricity. To                           value of new con Fracts entered into during the period.
manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural                                    Source of 2004 Year-End Valuation Prices offsets and enters into various derivative transactions for                                           Total                Maturity the remaining exposures pursuant to the Company's                                                  Fair Value Year 1              1-3 Years policies in areas such as counterparty exposure and                                                               (in millions) hedging practices. Company policy is that derivatives                   Actively quoted                $4.8           $3.8            $1.0 are to be used primarily for hedging purposes.                          External sources                1.0             1.0               -
Derivative positions are monitored using techniques that                Models and other include market valuation and sensitivity analysis.                          methods                        -               -              -
Contracts end of year          $5.8           $4.8           $1.0 To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been                          Unrealized gains and losses from mark to market designated as hedges. The weighted average interest rate                adjustments on derivative contracts related to the on outstanding variable long-term debt that has not been                Company's fuel hedging programs are recorded as hedged at January 1, 2005 was 2.04 percent. If the                      regulatory assets and liabilities. Realized gains and Company sustained a 100 basis point change in interest                  losses from these programs are included in fuel expense rates for all unhedged variable rate long-term debt, the                and are recovered through the Company's fuel cost change would affect annualized interest expense by                      recovery mechanism. See Note 3 to the financial approximately $8 million at January 1, 2005. The                        statements for information regarding the retail fuel Company is not aware of any facts or circumstances that                 hedging program. Gains and losses on derivative would significantly affect such exposures in the near                   contracts that are not designated as hedges are term. For further information, see Notes 1 and 6 to the                 recognized in the statements of income as incurred. At financial statements under "Financial Instruments."                     December 31, 2004, the fair value of derivative energy contracts was reflecte 1 in the financial statements as To mitigate residual risks relative to movements in                follows:
electricity prices, the Company enters into fixed-price                                                                Amounts contracts for the purchase and sale of electricity through                                                             (in millions) the wholesale electricity market and, to a lesser extent,                Regulatory liabilities, net                        $5.7 into similar contracts for gas purchases.
Other comprehensive income                             -
Net income                                          0.1 The Company has implemented a fuel hedging Total fair value                                $5.8 program at the instruction of the Georgia PSC. Fair Unrealized gains (losses) recognized in income in 2004, 2003, and 2002 were not material. The Company 21

MIANAGEMENT'S DISCUSSION AND ANALYSIS                     (continued)
Georgia Power Company 2004 Annual Report is exposed to market price risk in the event of                           In addition, as discussed in Note 2 to the financial nonperformance by counterparties to the derivative                   statements, the Company provides postretirement energy contracts. The Company's policy is to enter into             benefits to substantially all employees and funds trusts to agreements with counterparties that have investment                  the extent required by the Georgia PSC and the FERC.
grade credit ratings by Moody's and Standard & Poor's or with counterparties who have posted collateral to                      Other funding requirements related to obligations cover potential credit exposure. Therefore, the Company              associated with scheduled maturities of long-term does not anticipate market risk exposure from                       debt and preferred securities and the related interest, nonperformance by the counterparties. For additional                preferred stock dividends, leases, and other purchase information, see Notes I and 6 to the financial                      commitments are as follows. See Notes 1, 6, and 7 to statements under "Financial Instruments."                            the financial statements for additional information.
Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to be $911 million for 2005, $1.1 billion for 2006, and $1.2 billion for 2007. Environmental expenditures included in these amounts are $127 million,
$284 million, and $506 million for 2005, 2006, and 2007, respectively. Actual construction costs may vary from this estimate because of changes in such factors as:
business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission 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 Company currently has under construction Plant McIntosh Units 10 and 11 scheduled for completion in June 2005. In addition, construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission and distribution facilities, including those needed to meet the environmental standards previously discussed, are ongoing.
As a result of requirements by the Nuclear Regulatory Commission, the Company has established external trust funds for nuclear decommissioning costs.
For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning." Also as discussed in Note I to the financial statements under "Fuel Costs," in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.
22

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2004 Annual Report Contractual Obliiations 2006-                  2008-              After 2005            2007                   2009               2009              Total (in millions)
Long-term debt (a) __
Principal                                              $ 452              $ 456              $ 282               $ 3,942          $ 5,132 Interest                                                    232              426                  387                4,283            5,328 Preferred stock dividends(b)                                      1                 1                    1                    -                3 Operating leases                                                32                52                   42                   63              189 Purchase commitments(c) --
Capital (d)                                                 911            2,277                2,571                      -          5,759 Coal and nuclear fuel                                    1,731             2,722                  771                    96           5,320 Natural gas(e)                                              248              388                  389                1,669            2,694 Purchased power                                             339              692                  673                1,222            2,926 Long-term service agreements                                  6                19                  22                   150              197 Trusts(0) --
Nuclear decommissioning                                        9               14                   14                  124              161 Postretirement benefits                                        8               24                     -                    -              32 DOE assessments                                                   3                  4                    -                    -                7 Total                                                      $3,972             $7,075             $5,152               $11,549          $27,748 (a)    All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2005, as reflected in the statements of capitalization.
(b)    Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c)    The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were $1.4 billion, $1.2 billion, and $1.3 billion, respectively.
(d)   The Company forecasts capital expenditures over a five-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program.
(e)   Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on New York Mercantile Exchange future prices at December 31, 2004.
(f)    Projections of nuclear decommissioning trust contributions are based on the 2004 Retail Rate Plan. The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company's pension trust are currently expected during this period.
See Note 2 to the financial statements for additional information related to the pension plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company's corporate assets.
23

MANAGEMENT'S DISCUSSION AND ANALYSIS                         (continued)
Georgia Power Company 2004 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company's 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, environmental regulations and expenditures, the Company's projections for postretirement benefit trust contributions, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates,"
"projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
* the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
* current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil action against the Company;
* the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
* variations in demand for electricity, including those relating to weather, the general economy and population, and business growth (and declines);
* available sources and costs of fuels;
* ability to control costs;
* investment performance of the Company's employee benefit plans;
* advances in technology;
* state and federal rate regulations and the impact of pending and future rate cases and negotiations;
* internal restructuring or other restructuring options that may be pursued;
* potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
* the ability of counterparties of the Company to make payments as and when due;
* the ability to obtain new short- and long-term contracts with neighboring utilities;
* the direct or indirect effect on the Company's business resulting from terrorist incidents and the threat of terrorist incidents;
* interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;
* the ability of the Company to obtain additional generating capacity at competitive prices;
* catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;
* the direct or indirect effects on the Company's business resulting from incidents similar to the August 2003 power outage in the Northeast;
* the effect of accounting pronouncements issued periodically by standard-setting bodies; and
* other factors discussed elsewhere herein and in other reports filed by the Company (including the Form 10-K) from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
24

STATEMENTS OF INCOME For the Years Ended December 31, 2004, 2003, and 2002 Georgia Power Company 2004 Annual Report 2004           2003        2002 (in thousands)
Operating Revenues:
Retail sales                                                                  $4,776,985    $4,309,972    $4,288,097 Sales for resale --
Non-affiliates                                                                 246,545         259,376     270,678 Affiliates                                                                     166,245         174,855      98,323 Other revenues                                                                   181,033         169,304     165,362 Total operating revenues                                                       5,370,808      4,913,507    4,822,460 Operating Expenses:
Fuel                                                                           1,232,496      1,103,963    1,002,703 Purchased power --
Non-affiliates                                                                 304,978         258,621     264,814 Affiliates                                                                     671,098         516,944     419,839 Other operations                                                                 902,167         827,972     848,436 Maintenance                                                                      498,114         419,206     476,962 Depreciation and amortization                                                    275,488         349,984     403,507 Taxes other than income taxes                                                    227,806         212,827     201,857 Total operating expenses                                                       4,112,147      3,689,517    3,618,118 Operating Income                                                               1,258,661      1,223,990    1,204,342 Other Income and (Expense):
Allowance for equity funds used during construction                                26,659         10,752        7,622 Interest income                                                                     6,657         15,625        3,857 Interest expense, net of amounts capitalized                                    (182,370)      (182,583)    (168,391)
Interest expense to affiliate trusts                                              (44,565)
Distributions on mandatorily redeemable preferred securities                      (15,839)       (59,675)    (62,553)
Other income (expense), net                                                       (11,362)       (10,551)      (9,259)
Total other income and (expense)                                                (220,820)       (226,432)   (228,724)
Earnings Before Income Taxes                                                   1,037,841         997,558     975,618 Income taxes                                                                     379,170         366,311     357,319 Net Income                                                                       658,671         631,247     618,299 Dividends on Preferred Stock                                                          670            670          670 Net Income After Dividends on Preferred Stock                                   $658,001       $630,577     $617,629 The accompanying notes are an integral part of these financial statements.
25

STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004, 2003, and 2002 Georgia Power Company 2004 Annual Report 2004              2003             2002 (in thousands)
Operating Activities:
Net income                                                                      $ 658,671      $     631,247      $   618,299 Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization                                            361,958           424,321          459,563 Deferred income taxes and investment tax credits, net                    251,623           199,265            65,550 Deferred expenses - affiliates                                             (10,563)           (7,399)        (11,575)
Allowance for equity funds used during construction                        (26,659)          (10,752)          (7,622)
Pension, postretirement, and other employee benefits                         2,636           (16,162)        (64,771)
Tax benefit of stock options                                                 9,701            11,649            8,184 Hedge settlements                                                          (12,394)          (11,250)             860 Other, net                                                                 (27,624)           16,591         (82,190)
Changes in certain current assets and liabilities --
Receivables, net                                                     (225,454)            (4,870)          68,527 Fossil fuel stock                                                      (46,730)         (17,490)           82,711 Materials and supplies                                                    618            (7,677)          15,874 Other current assets                                                    (9,314)           (2,352)        (18,880)
Accounts payable                                                      132,001            (62,553)          64,902 Accrued taxes                                                          (64,563)           52,348           (6,540)
Accrued compensation                                                    (6,664)            (3,111)        (29,749)
Other current liabilities                                                5,836  -
19,845   -
45,915  -
Net cash provided from operating activities                                        993,079         1,211,650        1,209,058 Investing Activities:
Gross property additions                                                          (786,314)         (742,808)        (883,968)
Purchase of property from affiliates                                              (339,750)                 (2)
Cost of removal net of salvage                                                      (21,756)         (28,265)         (60,912)
Sale of property to affiliates                                                             -                  -       387,212 Change in construction payables, net of joint owner portion                             413          (32,223)           (7,411)
Other                                                                                31,503            17,124           37,557 Net cash used for investing activities                                          (1,115,904)         (786,174)        (527,522)
Financing Activities:
Increase (decrease) in notes payable, net                                            70,956         (220,400)        (389,860)
Proceeds --
Senior notes                                                                  600,000        1,000,000           500,000 Mandatorily redeemable preferred securities                                   200,000                    -       740,000 Capital contributions from parent company                                     260,068             40,809         165,299 Redemptions --
First mortgage bonds                                                                  -                  -         (1,860)
Pollution control bonds                                                               -                  -         (7,800)
Senior notes                                                                 (200,000)         (665,000)        (330,000)
Mandatorily redeemable preferred securities                                  (200,000)                   -      (589,250)
Capital distributions to parent company                                                    -                  -      (200,000)
Payment of preferred stock dividends                                                   (654)              (696)           (721)
Payment of common stock dividends                                                 (565,500)         (565,800)        (542,900)
Other                                                                               (17,247)          (22,563)         (30,831)
Net cash provided from (used for) financing activities                             147,623          (433,650)        (687,923)
Net Change in Cash and Cash Equivalents                                              24,798            (8,174)          (6,387)
Cash and Cash Equivalents at Beginning of Period                                      8,699            16,873          23,260 Cash and Cash Equivalents at End of Period                                    $      33,497    $        8,699     $     16,873 Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $8,920, $5,428, and $9,368 capitalized, respectively)       $228,190         $215,463         $203,707 Income taxes (net of refunds)                                                 127,115           145,048          326,698 The accompanying notes are an integral part of these financial statements.
26

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BALANCE SHEETS At December 31, 2004 and 2003 Georgia Power Company 2004 Annual Report Assets                                                                               2004                  2003 (in thousands)
Current Assets:
Cash and cash equivalents                                                    $     33,497         $       8,699 Receivables --
Customer accounts receivable                                                    317,937              261,771 Unbilled revenues                                                               140,027              117,327 Under recovered regulatory clause revenues                                      345,542              151,447 Other accounts and notes receivable                                              94,377              101,783 Affiliated companies                                                             17,042               52,413 Accumulated provision for uncollectible accounts                                  (7,100)             (5,350)
Fossil fuel stock, at average cost                                                184,267              137,537 Vacation pay                                                                       57,372               50,150 Materials and supplies, at average cost                                           270,422              271,040 Prepaid expenses                                                                   32,696              114,882 Other                                                                              25,260                    83 Total current assets                                                            1,511,339            1,261,782 Property, Plant, and Equipment:
In service                                                                     18,681,533           18,171,862 Less accumulated provision for depreciation                                     7,217,607            6,898,725 11,463,926           11,273,137 Nuclear fuel, at amortized cost                                                   124,745              129,056 Construction work in progress                                                     766,140              341,783 Total property, plant, and equipment                                           12,354,811           11,743,976 Other Property and Investments:
Equity investments in unconsolidated subsidiaries                                  66,192               38,714 Nuclear decommissioning trusts, at fair value                                     459,194              423,319 Other                                                                              66,775               52,386 Total other property and investments                                              592,161              514,419 Deferred Charges and Other Assets:
Deferred charges related to income taxes                                          505,664              509,887 Prepaid pension costs                                                             450,270              405,164 Unamortized debt issuance expense                                                  77,925               75,245 Unamortized loss on reacquired debt                                               176,825              177,707 Other regulatory assets                                                             72,639               84,901 Other                                                                              80,704               77,673 Total deferred charges and other assets                                         1,364,027            1,330,577 Total Assets                                                                 $15,822,338          $14,850,754 The accompanying notes are an integral part of these financial statements 27

BALANCE SHEETS At December 31, 2004 and 2003 Georgia Power Company 2004 Annual Report Liabilities and Stockholder's Equity                                                  2004                 2003 (in thousands)
Current Liabilities:
Securities due within one year                                                $    452,498        $       2,304 Notes payable                                                                      208,233             137,277 Accounts payable --
Affiliated                                                                       194,253             134,884 Other                                                                            310,763             238,069 Customer deposits                                                                  115,661             103,756 Accrued taxes --
Income taxes                                                                      78,269              39,970 Other                                                                            129,520             166,892 Accrued interest                                                                    74,529              70,844 Accrued vacation pay                                                                44,894              38,206 Accrued compensation                                                               127,340             134,004 Other                                                                               75,699             105,234 Total current liabilities                                                        1,811,659           1,171,440 Long-term Debt (See accompanying statements)                                     3,709,852           3,762,333 Long-term Debt Payable to Affiliated Trusts (See accompanying statements)          969,073 Mandatorily Redeemable Preferred Securities (See accompanying statements)                 -            940,000 Deferred Credits and Other Liabilities:
Accumulated deferred income taxes                                                2,556,040           2,439,373 Deferred credits related to income taxes                                           170,973             186,625 Accumulated deferred investment tax credits                                        300,018             312,506 Employee benefit obligations                                                       331,002             282,833 Asset retirement obligations                                                       504,515             475,585 Other cost of removal obligations                                                  411,692             412,161 Miscellaneous regulatory liabilities                                                92,611             249,687 Other                                                                               59,733              63,431 Total deferred credits and other liabilities                                     4,426,584           4,422,201 Total Liabilities                                                               10,917,168          10,295,974 Preferred Stock (See accompanying statements)                                       14,609               14,569 Common Stockholder's Equity (See accompanying statements)                        4,890,561           4,540,211 Total Liabilities and Stockholder's Euitv                                     $15.822,38I         $14,850,754 Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these financial statements.
28

STATEMENTS OF CAPITALIZATION At December 31, 2004 and 2003 Georgia Power Company 2004 Annual Report 2004                        2003             2004              2003 (in thousands)                       (percent of total)
Long-Term Debt:
Long-term notes payable --
5.50% due December 1, 2005                                                        $ 150,000                 $ 150,000 Variable rate (1.66% to 1.96% at 1/1/05) due 2005                                     300,000                    300,000 6.20% due February 1, 2006                                                            150,000                     150,000 4.875% due July 15, 2007                                                              300,000                    300,000 4.10% due August 15, 2009                                                             125,000                              -
Variable rate (2.48% at 1/1/05) due 2009                                              150,000                              -
4.00% to 6.70% due 2010-2044                                                        1,225,000                  1,100,000 Total long-term notes payable                                                               2,400,000                 2,000,000 Other long-term debt --
Pollution control revenue bonds -- non-collateralized:
1.08% to 5.45% due 2012-2034                                                       812,560                    812,560 Variable rate (1.24% to 2.30% at 1/1/05) due 2011-2032                                                                    873,330                    873,330 Total other long-term debt                                                                  1,685,890                  1,685,890 Capitalized lease obligations                                                                   76,982                     79,286 Unamortized debt premium (discount), net                                                           (522)                      (539)
Total long-term debt (annual interest requirement -- $172.7 million)                                                            4,162,350                 3,764,637 Less amount due within one year                                                               452,498                        2,304 Long-term debt excluding amount due within one year                                         3,709,852                 3,762,333               38.7%             40.6%
Long-term Debt Payable to Affiliated Trusts:
4.875% through 2007 due 2042*                                                               309,279                              -
5.875% to 7.125% due 2042 to 2044                                                          659,794 Total long-term debt payable to affiliated trusts (annual interest requirement -- $59.5 million)                                                     969,073                              -          10.1                0.0 Mandatorily Redeemable Preferred Securities:
$25 liquidation value --
6.85% due 2029                                                                                        -               200,000 7.125% due 2042                                                                                       -               440,000
$1,000 liquidation value -- 4.875% through 2007 due 2042*                                                -               300,000 Total mandatorily redeemable preferred securities                                                        -               940,000                0.0             10.2 Cumulative Preferred Stock:
$ 100 stated value at 4.60%
(annual dividend requirement -- $0.7 million)                                                14,609                     14,569               0.2               0.2 Common Stockholder's Equity:
Common stock, without par value --
Authorized - 15,000,000 shares Outstanding - 7,761,500 shares                                                              344,250                    344,250 Paid-in capital                                                                          2,478,268                 2,208,538 Retained earnings                                                                           2,102,798                 2,010,297 Accumulated other comprehensive income (loss)                                                  (34,755)                   (22,874)
Total common stockholder's equity                                                           4,890,561                 4,540,211               51.0              49.0 Total Capitalization                                                                      $9,584,095                $9,257,113              100.0%             100.0%
*The fixed rate thereafter is determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 3.05%.
The accompanying notes are an integral part of these financial statements.
29

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2004, 2003, and 2002 Georgia Power Company 2004 Annual Report Other Common         Paid-In     Retained       Comprehensive Stock        Capital     Earnings        Income (loss)        Total (in thousands)
Balance at December 31, 2001                                         $344,250     $2,182,597   $1,870,791             $(     153) $4,397,485 Net income after dividends on preferred stock                                -               -      617,629                     -    617,629 Capital distributions to parent company                                      -      (200,000)              -                        (200,000)
Capital contributions from parent company                                    -       173,483               -                   -     173,483 Other comprehensive income (loss)                                            -               -             -           (11,250)       (11,250)
Cash dividends on common stock                                               -               -     (542,900)                    -   (542,900)
Balance at December 31, 2002                                          344,250      2,156,080     1,945,520             (11,403)    4,434,447 Net income after dividends on preferred stock                                -               -      630,577                     -    630,577 Capital contributions from parent company                                    -        52,458               -                   -       52,458 Other comprehensive income (loss)                                            -               -             -           (11,471)      (11,471)
Cash dividends on common stock                                               -               -    (565,800)                         (565,800)
Balance at December 31, 2003                                          344,250      2,208,538     2,010,297             (22,874)    4,540,211 Net income after dividends on preferred stock                                -              -       658,001                    -     658,001 Capital contributions from parent company                                    -       269,769               -                   -     269,769 Other comprehensive income (loss)                                            -              -              -           (11,881)      (11,881)
Cash dividends on common stock                                               -              -     (565,500)                    -    (565,500)
Other                                                                        -            (39)                                             (39)
Balance at December 31, 2004                                         $344,250     $2,478,268   $2,102,798            $(34,755)    $4,890,561 The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2004, 2003, and 2002 Georgia Power Company 2004 Annual Report 2004                      2003          2002 (in thousands)
Net income after dividends on preferred stock                                                     $658,001           $630,577       $617,629 Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of
      $(3,861), $(5,133) and $(4,853), respectively                                                  (6,122)             (8,138)       (7,693)
Change in fair value of marketable securities, net of tax of
        $(114)                                                                                         (181)
Changes in fair value of qualifying hedges, net of tax of
     $(5,046), $(3,241) and $(2,502), respectively                                                   (7,999)             (5,550)       (3,555)
Less: Reclassification adjustment for amounts included in net income, net of tax of $1,528, $1,208 and $-, respectively                                   2,421               2,217             (2)
Total other comprehensive income (loss)                                                    (11,881)           (11,471)      (11,250)
Comprehensive Income                                                                              $646,120           $619,106      $606,379 The accompanying notes are an integral part of these financial statements.
30

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NOTES TO FINANCIAL STATEMENTS Georgia Power Company 2004 Annual Report
: 1. 

==SUMMARY==
OF SIGNIFICANT                                     accounting policies and practices prescribed by its ACCOUNTING POLICIES                                        regulatory commissions. The preparation of financial statements in conformity with accounting principles General                                                       generally accepted in the United States requires the use of estimates and the actual results may differ from those Georgia Power Company (Company) is a wholly owned             estimates.
subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern               Certain prior years' data presented in the financial Power Company (Southern Power), Southern Company              statements have been reclassified to conform with Services (SCS), Southern Communications Services              current year presentation.
(SouthernLINC Wireless), Southern Company Gas (Southern Company GAS), Southern Company Holdings             Affiliate Transactions (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and             The Company has an agreement with SCS under which other direct and indirect subsidiaries. The retail            the following services are rendered to the Company at operating companies -- Alabama Power, the Company,            direct or allocated cost: general and design engineering, Gulf Power, Mississippi Power, and Savannah Electric --       purchasing, accounting and statistical analysis, finance provide electric service in four Southeastern states.         and treasury, tax, information resources, marketing, Southern Power constructs, owns, and manages Southern         auditing, insurance and pension administration, human Company's competitive generation assets and sells             resources, systems and procedures, and other services electricity at market-based rates in the wholesale market. with respect to business and operations and power pool Contracts among the retail operating companies and            operations. Costs for these services amounted to $292 Southern Power -- related to jointly owned generating         million in 2004, $303 million in 2003, and $318 million facilities, interconnecting transmission lines, or the        in 2002. Cost allocation methodologies used by SCS are exchange of electric power -- are regulated by the            approved by the SEC and management believes they are Federal Energy Regulatory Commission (FERC) and/or            reasonable.
the Securities and Exchange Commission (SEC). SCS --
the system service company -- provides, at cost,                   The Company has an agreement with Southern specialized services to Southern Company and the              Nuclear under which the following nuclear-related subsidiary companies. SouthermLINC Wireless provides          services are rendered to the Company at cost: general digital wireless communications services to the retail        executive and advisory services; general operations, operating companies and also markets these services to        management and technical services; administrative the public within the Southeast. Southern Telecom              services including procurement, accounting, employee provides fiber cable services within the Southeast.           relations, and systems and procedures services; strategic Southern Company GAS is a competitive retail natural          planning and budgeting services; and other services with gas marketer serving customers in Georgia. Southern           respect to business and operations. Costs for these Holdings is an intermediate holding subsidiary for             services amounted to $311 million in 2004, $289 million Southern Company's investments in synthetic fuels and          in 2003, and $301 million in 2002.
leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides                 The Company has an agreement with Southern services to Southern Company's nuclear power plants.          Power under which the Company operates and maintains Southern Power owned plants Dahlberg, Franklin, Southern Company is registered as a holding               Wansley, and Stanton at cost. Reimbursements under company under the Public Utility Holding Company Act           these agreements with Southern Power amounted to $4.9 of 1935, as amended (PUHCA). Both Southern                     million in 2004, $5.3 million in 2003, and $5.3 million Company and its subsidiaries are subject to the                in 2002.
regulatory provisions of the PUHCA. In addition, the Company is subject to regulation by the FERC and the               The Company has an agreement with SouthernLINC Georgia Public Service Commission (PSC). The                   Wireless under which the Company receives digital Company follows accounting principles generally                wireless communications services and purchases digital accepted in the United States and complies with the            equipment. Costs for these services amounted to $7.7 31

NOTES (continued)
Georgia Power Company 2004 Annual Report million in 2004, $7.4 million in 2003 and $5.9 million in     GAS, may jointly enter into various types of wholesale 2002.                                                         energy, natural gas and certain other contracts, either directly or through SCS as agent. Each participating Southern Company holds a 30 percent ownership in        company may be jointly and severally liable for the Alabama Fuel Products, LLC (AFP), which produces              obligations incurred under these agreements. See Note 7 synthetic fuel. The Company has an agreement with an          under "Fuel Commitments" for additional information.
indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company           Revenues provides certain accounting functions, including processing and paying fuel transportation invoices, and       Energy and other revenues are recognized as services are the Company is reimbursed for its expenses. Amounts           provided. Unbilled revenues are accrued at the end of billed under this agreement totaled approximately $53         each fiscal period. Electric rates for the Company million in 2004 and $38 million in 2003. In addition, the     include provisions to adjust billings for fluctuations in Company purchases synthetic fuel from AFP for use at          fuel costs, fuel hedging, the energy component of plants Branch, McDonough, and Bowen. Fuel purchases           purchased power costs, and certain other costs.
totaled $163 million in 2004 and $91 million in 2003.         Revenues are adjusted for differences between recoverable costs and amounts billed in current regulated The Company has entered into several purchased          rates.
power agreements (PPAs) with Southern Power for capacity and energy. Purchased power costs were $282               The Company has a diversified base of customers.
million, $203 million and $128 million in 2004, 2003          No single customer or industry comprises 10 percent or and 2002, respectively. Additionally, the Company             more of revenues. For all periods presented, recorded $11 million and $7 million of prepaid capacity       uncollectible accounts averaged less than I percent of expenses included on the balance sheets at December 31,       revenues despite an increase in customer bankruptcies.
2004 and 2003, respectively. See Note 7 under "Purchased Power Commitments" for additional                  Fuel Costs information.
Fuel costs are expensed as the fuel is used. Fuel expense The Company has an agreement with Gulf Power            includes the cost of purchased emission allowances as under which Gulf Power jointly owns a portion of Plant        they are used. Fuel expense also includes the Scherer. Under this agreement, the Company operates          amortization of the cost of nuclear fuel and a charge, Plant Scherer and Gulf Power reimburses the Company          based on nuclear generation, for the permanent disposal for its proportionate share of the related expenses which    of spent nuclear fuel. Total charges for nuclear fuel were $6.8 million in 2004, $4.9 million in 2003, and          included in fuel expense amounted to $73 million in
$4.5 million in 2002. The Company has an agreement            2004, $74 million in 2003, and $71 million in 2002. The with Savannah Electric under which the Company                Company has contracts with the Department of Energy jointly owns a portion of Plant McIntosh. Under this          (DOE) that provide for the permanent disposal of spent agreement, Savannah Electric operates Plant McIntosh          nuclear fuel. The DOE failed to begin disposing of and the Company reimburses Savannah Electric for its          spent nuclear fuel in 1998 as required by the contracts, proportionate share of the related expenses which were        and the Company is pursuing legal remedies against the
 $3.3 million in 2004, $3.7 million in 2003, and $2.2         government for breach of contract. Sufficient pool million in 2002. See Note 4 for additional information.      storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for Also see Note 4 for information regarding the           both units into 2015. Construction of an on-site dry Company's ownership in and purchased power                   storage facility at Plant Vogtle is expected to begin in agreement with Southern Electric Generating Company          sufficient time to maintain pool full-core discharge (SEGCO) and Note 5 for information on certain deferred       capability. At Plant Hatch, an on-site dry storage facility tax liabilities due to affiliates.                           became operational in 2000 and can be expanded to accommodate spent fuel through the life of the plant.
The retail operating companies, including the Company, Southern Power, and Southern Company 32

NOTES     (continued)
Georgia Power Company 2004 Annual Report Also, the Energy Policy Act of 1992 required the              Regulatory assets and (liabilities) reflected in the establishment of a Uranium Enrichment                         Company's balance sheets at December 31 relate to the Decontamination and Decommissioning Fund, which is            following:
funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-                                                      2004         2003 Note year period, ending in 2008. This fund will be used by                                                           (in millions) the DOE for the decontamination and decommissioning             Deferred income tax charges                  $ 506       $ 510 (a) of its nuclear fuel enrichment facilities. The law              Premium on reacquired debt                      177          178 (b)
Corporate building lease                         53           54 (f) provides that utilities will recover these payments in the                                                       57           50 (d)
Vacation pay same manner as any other fuel expense. The Company -            Postretirement benefits                          20           23 (f)
- based on its ownership interest -- estimates its              DOE assessments                                  10            13 (c) remaining liability at December 31, 2004 under this law         Generating plant outage costs                    40           49 (h) to be approximately $7 million.                                 Other regulatory assets                          11             1 (I)
Asset retirement obligation                     (20)         (16) (a)
Income Taxes                                                    Other cost of removal obligations              (412)        (412) (a)
Accelerated cost recovery                          -        (111) (e)
The Company uses the liability method of accounting for         Deferred income tax credits                    (171)        (187) (a)
Environmental remediation reserve               (22)         (21) (g) deferred income taxes and provides deferred income Purchased power                                    -         (77) (e) taxes for all significant income tax temporary                                                                    (6)          (3) (f)
Other regulatory liabilities differences. Investment tax credits utilized are deferred                                                    $  243       $    51 Total and amortized to income over the average lives of the Note: The recovery and amortization periods for these regulatory related property.                                                   assets and (liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred Manufacturer's Tax Credits                                         income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 60 years. Asset retirement and removal liabilities will be The State of Georgia provides a tax credit for qualified            settled and trued up following completion of the related investment property to manufacturing companies that                activities.
construct new facilities. The credit ranges from 1            (b) Recovered over either the remaining life of the original issue percent to 8 percent of qualified construction                      or, if refinanced, over the life of the new issue which may expenditures depending upon the county in which the                range up to 50 years.
(c) Assessments for the decontamination and decommissioning of new facility is located. The Company's policy is to                 the DOE's nuclear fuel enrichment facilities are recorded recognize these credits when management believes that               annually from 1993 through 2008.
they are more likely than not to be allowed by the           (d) Recorded as earned by employees and recovered as paid, Georgia Department of Revenue. Manufacturer's tax                  generally within one year.
credits of $12.9 million, $12.0 million, and $4.7 million    (e) Amortized over a three-year period ending in 2004. See Note 3 under "Retail Rate Orders."
were recorded on the Company's books in 2004,2003            (f) Recorded and recovered or amortized as approved by the and 2002, respectively.                                            Georgia PSC.
(g) Amortized over a three-year period ending in 2007. See Note Regulatory Assets and Liabilities                                  3 under "Retail Rate Orders."
(h) See "Property, Plant, and Equipment' herein.
The Company is subject to the provisions of Financial             In the event that a portion of the Company's Accounting Standards Board (FASB) Statement No. 71,          operations is no longer subject to the provisions of Accounting for the Effects of Certain Types of               Statement No. 71, the Company would be required to Regulation. Regulatory assets represent probable future      write off related regulatory assets and liabilities that are revenues associated with certain costs that are expected     not specifically recoverable through regulated rates. In to be recovered from customers through the ratemaking        addition, the Company would be required to determine if process. Regulatory liabilities represent probable future    any impairment to other assets, including plant, exists reductions in revenues associated with amounts that are      and, if impaired, write down the assets to their fair value.
expected to be credited to customers through the             All regulatory assets and liabilities are reflected in rates.
ratemaking process.
33

NOTES      (continued)
Georgia Power Company 2004 Annual Report Depreciation and Amortization                                 PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations Depreciation of the original cost of plant in service is      previously accrued will continue to be reflected on the provided primarily by using composite straight-line           balance sheets as a regulatory liability. Therefore, the rates, which approximated 2.6 percent in 2004, 2.7            Company had no cumulative effect to net income percent in 2003, and 2.9 percent in 2002. Under a new         resulting from the adoption of Statement No. 143.
retail rate plan for the Company ending December 31, 2007 (2004 Retail Rate Plan), the depreciation rates               The liability recognized to retire long-lived assets have been revised by the Georgia PSC. When property           primarily relates to the Company's nuclear facilities, subject to depreciation is retired or otherwise disposed      which include the Company's ownership interests in of in the normal course of business, its original cost --     plants Hatch and Vogtle. The fair value of assets legally together with the cost of removal, less salvage -- is         restricted for settling retirement obligations related to charged to accumulated depreciation. Minor items of           nuclear facilities as of December 31, 2004 was $459 property included in the original cost of the plant are       million. In addition, the Company has recognized retired when the related property unit is retired.            retirement obligation 3 related to various landfill sites, ash ponds, and underground storage tanks. The Under the three-year retail rate plan for the            Company has also identified retirement obligations Company ending December 31, 2004 (2001 Retail Rate            related to certain transmission and distribution facilities, Plan), the Company discontinued recording accelerated         leasehold improvements, equipment on customer depreciation and amortization. Also, the Company was          property, and property associated with the Company's ordered to amortize $333 million -- the cumulative            rail lines. However, Liabilities for the removal of these balance previously expensed -- equally over three years       facilities have not been recorded because no reasonable as a credit to amortization expense beginning January         estimate can be made regarding the timing of any related 2002. Additionally, the Company was ordered to                retirements. The Company will continue to recognize in recognize new Georgia PSC certified purchased power           the statements of income the ultimate removal costs in costs in rates evenly over the three years covered by the     accordance with its regulatory treatment. Any difference 2001 Retail Rate Plan. As a result of the purchased           between costs recognized under Statement No. 143 and power regulatory adjustment, the Company recorded             those reflected in rates will be recognized as either a amortization expenses of $14 million and $63 million in       regulatory asset or liability in the balance sheets. In 2003 and 2002, respectively. The Company recorded a           2003, the Company revised the estimated cost to retire credit to amortization expense of $77 million in 2004.        plants Hatch and Vogtle as a result of a new 2003 site-See Note 3 under "Retail Rate Orders" for additional          specific decommissioning study. The effect of the information.                                                  revision is a decrease of $24 million for the Statement No. 143 liability included in "Asset Retirement Asset Retirement Obligations                                  Obligations" with a corresponding decrease in property, and Other Costs of Removal                                    plant and equipment. See "Nuclear Decommissioning" herein for further information on amounts included in Effective January 1, 2003, the Company adopted FASB           rates.
Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 established new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset's future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Although Statement No.
143 does not permit the continued accrual of future retirement costs for long-lived assets that the Company does not have a legal obligation to retire, the Company has received accounting guidance from the Georgia 34

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Georgia Power Company 2004 Annual Report Details of the asset retirement obligations included         study as of December 31, 2004 for the Company's in the balance sheets are as follows:                             ownership interests in plants Hatch and Vogtle were as follows:
2004          2003 (in millions)                                            Plant           Plant Balance beginning of year               $476          $469                                          Hatch          Vogtle Liabilities incurred                         -              -     Site study year                    2003            2003 Liabilities settled                       (2)              -     Decommissioning periods:
Accretion                                31              31         Beginning year                  2034            2027 Cash flow revisions                         -           (24)        Completion year                 2065            2048 Balance end of year                    $505          $476                                                 (in millions)
Site study costs:
Nuclear Decommissioning                                               Radiated structures              $497            $452 Non-radiated structures            49               58 The Nuclear Regulatory Commission (NRC) requires                   Total                               $546            $510 licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of                 The decommissioning cost estimates are based on funds for future decommissioning. The Company has                 prompt dismantlement and removal of the plant from established external trust funds to comply with the               service. The actual decommissioning costs may vary NRC's regulations. The funds set aside for                        from the above estimates because of changes in the decommissioning are managed and invested in                       assumed date of decommissioning, changes in NRC accordance with applicable requirements of various                requirements, or changes in the assumptions used in regulatory bodies, including the NRC, the FERC, and               making these estimates.
the Georgia PSC as well as the Internal Revenue Service (IRS). Funds are invested in a tax efficient                   Annual provisions for nuclear decommissioning are manner in a diversified mix of equity and fixed income            based on an annuity method as approved by the Georgia securities. Equity securities typically range from 50 to          PSC. The amount expensed in 2004 and fund balances 75 percent of the funds and fixed income securities               were as follows:
from 25 to 50 percent. Amounts previously recorded in internal reserves are being transferred into the external                                               Plant          Plant trust funds over periods approved by the Georgia PSC.                                                  Hatch          Vogtle The NRC's minimum external funding requirements are                                                        (in millions) based on a generic estimate of the cost to decommission              Amount expensed in 2004           $   7           $ 2 only the radioactive portions of a nuclear unit based on             Accumulated provisions:
the size and type of reactor. The Company has filed                    External trust funds, at fair   $294            $165 plans with the NRC to ensure that -- over time -- the                    value deposits and earnings of the external trust funds will                 Internal reserves                    -              2 provide the minimum funding amounts prescribed by                    Total                             $294            $167 the NRC.
Based on the 2001 Retail Rate Plan, effective Site study cost is the estimate to decommission a January 1, 2002, the Georgia PSC decreased the annual specific facility as of the site study year. The estimated decommissioning costs for ratemaking to $9 million.
costs of decommissioning based on the most current This amount was based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2000. The estimates were $383 million and $282 million for plants Hatch and Vogtle, respectively.
Significant assumptions used to determine the costs for ratemaking included an estimated inflation rate of 4.7 percent and an estimated trust earnings rate of 6.5 percent.
35

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Georgia Power Company 2004 Annual Report Effective January 1, 2005, the Georgia PSC has                 The cost of replacements of property -- exclusive of ordered the annual decommissioning costs for                   minor items of property -- is capitalized. The cost of ratemaking be decreased from $9 million to $7 million.         maintenance, repairs, and replacement of minor items of This amount is based on the NRC generic estimate to            property is charged to maintenance expense as incurred decommission the radioactive portion of the facilities as      or performed with the exception of certain generating of 2003. The estimates are $421 million and $326               plant maintenance costs. As mandated by the Georgia million for plants Hatch and Vogtle, respectively.             PSC, the Company defers and amortizes nuclear Significant assumptions used to determine the costs for        refueling costs over the unit's operating cycle before the ratemaking include an estimated inflation rate of 3.1          next refueling. The refueling cycles are 18 and 24 percent and an estimated trust earnings rate of 5.1            months for plants Vogtle and Hatch, respectively. In percent. Another significant assumption used was the           accordance with the 2001 Retail Rate Plan, the Company change in the operating license for Plant Hatch. In            defers the costs of certain significant inspection costs for January 2002, the NRC granted the Company a 20-year            the combustion turbines at Plant McIntosh and amortizes extension of the licenses for both units at Plant Hatch        such costs over 10 years, which approximates the which permits the operation of units 1 and 2 until 2034        expected maintenance cycle.
and 2038, respectively. The Company expects the Georgia PSC to periodically review and adjust, if              Impairment of Long-Lived Assets and Intangibles necessary, the amounts collected in rates for the anticipated cost of decommissioning.                           The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that Allowance for Funds Used During Construction                   the carrying value of such assets may not be recoverable.
(AFUDC) and Interest Capitalized                               The determination of whether an impairment has occurred is based on either a specific regulatory In accordance with regulatory treatment, the Company           disallowance or an estimate of undiscounted future cash records AFUDC. AFUDC represents the estimated debt             flows attributable to the assets, as compared with the and equity costs of capital funds that are necessary to        carrying value of the assets. If an impairment has finance the construction of new regulated facilities.          occurred, the amount of the impairment recognized is While cash is not realized currently from such allowance,      determined by either the amount of regulatory it increases the revenue requirement over the service life     disallowance or by estimating the fair value of the assets of the plant through a higher rate base and higher             and recording a loss if the carrying value is greater than depreciation expense. Interest related to the construction     the fair value. For assets identified as held for sale, the of new facilities not included in the Company's retail         carrying value is compared to the estimated fair value rates is capitalized in accordance with standard interest      less the cost to sell in order to determine if an capitalization requirements. For the years 2004, 2003,         impairment provision is required. Until the assets are and 2002, the average AFUDC rates were 8.22 percent,           disposed of, their estimated fair value is re-evaluated 5.51 percent, and 3.79 percent, respectively. AFUDC and        when circumstances or events change. See Note 3 under interest capitalized, net of taxes, were 4.9 percent of net    "Retail Rate Orders" and "Plant McIntosh Construction income after dividends on preferred stock for 2004 and         Project" for information regarding the disallowance of less than 3 percent for 2003 and 2002.                         Plant McIntosh costs under the 2004 Retail Rate Plan.
Property, Plant, and Equipment                                 Storm Damage Reserve Property, plant, and equipment is stated at original cost,     The Company maintains a reserve for property less regulatory disallowances and impairments. Original        damage to cover the cost of damages from major cost includes: materials; labor; minor items of property;      stonrs to its transmission and distribution lines and appropriate administrative and general costs;                  the cost of uninsured damages to its generation payroll-related costs such as taxes, pensions, and other       facilities and other property as mandated by the benefits; and the interest capitalized and/or cost of funds    Georgia PSC. These costs are expected to be used during construction.                                      recovered through regular monthly accruals which total $6.3 million annually under the 2004 Retail Rate Plan.
36

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Georgia Power Company 2004 Annual Report Cash and Cash Equivalents                                     Scholes stock option pricing model. The following table shows the assumptions and the weighted coverage. Fair For purposes of the financial statements, temporary cash      values of stock options are as follows:
investments are considered cash equivalents. Temporary cash investments are securities with original maturities                                         2004      2003         2002 of 90 days or less.
Interest rate                      3.10% 2.70%             2.80%
Materials and Supplies                                        Average expected life of stock options (in years)          5.0        4.3          4.3 Generally, materials and supplies include the average         Expected volatility of costs of transmission, distribution, and generating plant       common stock                    19.60% 23.60%          26.30%
materials. Materials are charged to inventory when            Expected annual dividends purchased and then expensed or capitalized to plant, as         on common stock                 $1.40      $1.37       $1.34 appropriate, when installed.                                  Weighted average fair value of stock options granted          $3.29      $3.59       $3.37 Stock Options Financial Instruments Southern Company provides non-qualified stock options to a large segment of the Company's                   The Company uses derivative financial instruments to employees ranging from line management to                     limit exposures to fluctuations in interest rates, the prices executives. The Company accounts for its stock-               of certain fuel purchases and electricity purchases and based compensation plans in accordance with                   sales. All derivative financial instruments are Accounting Principles Board Opinion No. 25.                   recognized as either assets or liabilities and are measured Accordingly, no compensation expense has been                 at fair value.
recognized because the exercise price of all options granted equaled the fair-market value of Southern                  The Company and its affiliates, through SCS acting Company's common stock on the date of grant.                  as their agent, enter into commodity related forward and When options are exercised, the Company receives a            option contracts to limit exposure to changing prices on capital contribution from Southern Company                    certain fuel purchases and electricity purchases and equivalent to the related income-tax benefit.                 sales. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of The pro forma impact of fair-value accounting for        a derivative are exempt from fair value accounting options granted on earnings is as follows:                    requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow As                 Pro      hedges of anticipated transactions. This results in the Net Income                  Reported              Forma     deferral of related gains and losses in other (in thousands) comprehensive income or regulatory assets or liabilities 2004                          $658,001            $654,482    as appropriate until the hedged transactions occur. Any 2003                          $630,577            $626,738    ineffectiveness is recognized currently in net income.
Other derivative contracts are marked to market through 2002                          $617,629            $613,483    current period income and are recorded on a net basis in the statements of income.
The estimated fair value of stock options granted in 2004, 2003, and 2002 were derived using the Black-                 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.
37

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Georgia Power Company 2004 Annual Report The Company's financial instruments for which the          2. RETIREMENT BENEFITS carrying amounts did not equal fair value at December 31 were as follows:                                             The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is Carrying           Fair    funded in accordance with Employee Retirement Income Amount            Value    Security Act of 1974, as amended (ERISA),
Long-term debt:                           (in millions)         requirements. No contributions to the plan are expected At December 31, 2004               $5,055          $5,125    for the year ending December 31, 2005. The Company At December 31, 2003               $3,685          $3,739    also provides certain non-qualified benefit plans for a Preferred securities:                                           selected group of management and highly compensated At December 31, 2004                                         employees. Benefits under these non-qualified plans are At December 31, 2003                  $940           $976    funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits The fair values were based on either closing market        for retired employees. The Company funds related trusts prices or closing prices of comparable instruments. See         to the extent required by the Georgia PSC and the "Variable Interest Entities" herein and Note 6 under            FERC. For the year ended December 31, 2005, such "Mandatorily Redeemable Preferred Securities/Long-              contributions are expected to total approximately $7.7 Term Debt Payable to Affiliated Trusts" for further             million.
information.
The measurement date for plan assets and Comprehensive Income                                            obligations is September 30 for each year.
The objective of comprehensive income is to report a            Pension Plans measure of all changes in common stock equity of an enterprise that result from transactions and other              The accumulated benefit obligation for the pension plans economic events of the period other than transactions           was $1.7 billion in 2004 and $1.6 billion in 2003.
with owners. Comprehensive income consists of net               Changes during the year in the projected benefit income, changes in the fair value of marketable                 obligations, accumulated benefit obligations, and the fair securities and qualifying cash flow hedges, and changes         value of plan assets were as follows:
in additional minimum pension liability, less income taxes less reclassifications for amounts included in net                                                Projected income.                                                                                            Benefit Obligation 2004           2003 Variable Interest Entities                                                                              (in millions)
Balance at beginning of year      $1,727         $1,564 On March 31, 2004, the Company prospectively                     Service cost                           42             38 adopted FASB Interpretation No. 46R, "Consolidation              Interest cost                        101             100 of Variable Interest Entities," which requires the               Benefits paid                         (85)           (83) primary beneficiary of a variable interest entity to             Plan amendments                           1            6 consolidate the related assets and liabilities. The Actuarial loss                         99            102 adoption of Interpretation No. 46R had no impact on the net income of the Company. However, as a result              Balance at end of year            $1,885         $1,727 of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts on the balance sheets. This treatment resulted in a $29 million increase in both total assets and total liabilities as of March 31, 2004.
38

NOTES (continued)
Georgia Power Company 2004 Annual Report The prepaid pension asset, net is reflected in the Plan Assets              balance sheets in the following line items:
2004           2003 (in millions)                                                     2004        2003 (in millions)
Balance at beginning of year         $2,055          $1,838 Actual return on plan assets              207             294      Prepaid pension asset                     $450        $405 Benefits paid                              (81)           (77)     Employee benefit obligations                (89)         (82)
Balance at end of year               $2,181          $2,055        Other property and investments -
other                                       19          18 Pension plan assets are managed and invested in               Accumulated other accordance with all applicable requirements including                comprehensive income                       36           26 ERISA and the Internal Revenue Code of 1986, as                    Prepaid pension asset, net                $416        $367 amended (Internal Revenue Code). The Company's investment policy covers a diversified mix of assets,                   Components of the plans' net periodic cost were as including equity and fixed income securities, real estate,         follows:
and private equity, as described in the table below.
Derivative instruments are used primarily as hedging                                                  2004       2003         2002 tools but may also be used to gain efficient exposure to                                                      (in millions) the various asset classes. The Company primarily minimizes the risk of large losses through diversification         Service cost                      $ 42        $ 38 $ 36 but also monitors and manages other aspects of risk.               Interest cost                       101         100         107 Expected return on plan assets     (180)       (179)       (179)
Plan Assets                   Recognized net gain                   (5)       (19)         (27)
Target          2004 2003              Net amortization                       7           6           4 Domestic equity              37%               36% 37%             Net pension (income)              $ (35)      $(54) $ (59)
International equity         20                20         20 Fixed income                 26                26         24           Future benefit payments reflect expected future Real estate                  10                10         11       service and are estimated based on assumptions used to Private equity                7                  8         8       measure the projected benefit obligation for the pension Total                   100%              100% 100%            plans. At December 31, 2004, estimated benefit payments were as follows:
The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets                                                Benefit Payments (in millions) were as follows:
2005                                                 $ 83 2004        2003      2006                                                    83 (in millions)      2007                                                    86 Funded status                                $295        $328      2008                                                    89 Unrecognized transition amount                   (8)       (13)    2009                                                    93 Unrecognized prior service cost                108         118     2010 to 2014                                         $568 Unrecognized net actuarial gain (loss)                                       21         (66)
Prepaid pension asset, net                   $416        $367 39

NOTES      (continued)
Georgia Power Company 2004 Annual Report Postretirement Benefits                                                   The accrued postretirement costs recognized in the balance sheets were as follows:
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as                                                       2004         2003 follows:                                                                                                          (in millions)
Funded status                           $(428)        $(458)
Accumulated                 Unrecognized transition obligation            78          87 Benefit Obligation              Unrecognized prior service cost               27          91 2004               2003        Unrecognized net loss                      203          171 (in millions)             Fourth quarter contributions                  15            9 Balance at beginning of year           $723               $627        Employee benefit obligations Service cost                                10                9          recognized in the balance sheets     $(105)        $(100)
Interest cost                              41                40 Benefits paid                             (31)              (29)            Components of the postretirement plans' net Actuarial loss                              42               76       periodic cost were as follows:
Plan amendments                           (59)                 -
Balance at end of year                  $726              $723                                            2004     2003       2002 (in millions)
Plan Assets                        Service cost                        $ 10       $ 9       $ 8 2004               2003        Interest cost                         41         40         40 (in millions)             Expected return on plan assets                     (25) (24)             (20)
Balance at beginning of year         $265                $199                                               18        16         15 Net amortization Actual return on plan assets             32                 36                                                                $ 43 Net postretirement cost             $ 44 $ 41 Employer contributions                   33                 59 Benefits paid                           (31)               (29)
In the third quarter 2004, the Company Balance at end of year               $299                $265 prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements Postretirement benefits plan assets are managed and             related to the Medicare Prescription Drug, invested in accordance with all applicable requirements,              Improvement, and Modernization Act of 2003 including ERISA and the Internal Revenue Code. The                   (Medicare Act). The Medicare Act provides a 28 Company's investment policy covers a diversified mix                  percent prescription drug subsidy for Medicare of assets, including equity and fixed income securities,              eligible retirees. FSP 106-2 requires recognition of real estate, and private equity, as described in the table            the impacts of the Medicare Act in the accumulated below. Derivative instruments are used primarily as                  postretirement benefit obligation (APBO) and future hedging tools but may also be used to gain efficient                 cost of service for postretirement medical plans. The exposure to the various asset classes. The Company                    effect of the subsidy reduced the Company's expenses primarily minimizes the risk of large losses through                  for the six months ended December 31, 2004 by diversification, but also monitors and manages other                  approximately $5 million and is expected to have a aspects of risk.                                                      similar impact on future expenses. The subsidy's impact on the postretirement medical plan APBO was Plan Assets                 a reduction of approximately $72 million. However, Target        2004         2003        the ultimate impact on future periods is subject to Domestic equity                43%             42%           42%     federal regulations governing the subsidy created in International equity           20              23            21      the Medicare Act which are being finalized.
Domestic fixed income           19             19              -
Global fixed income             13             11            32           Future benefit payments, including prescription drug Real estate                      3              3              3     benefits, reflect expected future service and are Private equity                   2              2              2     estimated based on assumptions used to measure the Total                       100%            100%          100%     accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug 40

NOTES      (continued)
Georgia Power Company 2004 Annual Report subsidy receipts expected as a result of the Medicare Act           The Company provides a 75 percent matching as follows:                                                         contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan Benefit        Subsidy                   for the years 2004, 2003, and 2002 were $18 million, Payments       Receipts      Total       $18 million, and $17 million, respectively.
(in millions) 2005                         $ 28          $ -          $ 28       3. CONTINGENCIES AND REGULATORY 2006                            31            (3)          28           MATTERS 2007                            34            (3)          31 2008                            37            (4)          33      General Litigation Matters 2009                            41            (4)          37 2010 to 2014                 $257         $(28)         $229       The Company is subject to certain claims and legal actions arising in the ordinary course of business. In The weighted average rates assumed in the actuarial            addition, the Company's business activities are subject calculations used to determine both the benefit                     to extensive governmental regulation related to public obligations and the net periodic costs for the pension and          health and the environment. Litigation over postretirement benefit plans were:                                 environmental issues and claims of various types, including property damage, personal injury, and citizen 2004       2003         2002     enforcement of environmental requirements, has Discount                           5.75% 6.00%            6.50%     increased generally throughout the United States. In Annual salary increase             3.50       3.75        4.00     particular, personal injury claims for damages caused by Long-term return on plan                                            alleged exposure to hazardous materials have become assets                         8.50       8.50         8.50    more frequent. The ultimate outcome of such litigation against the Company cannot be predicted at this time; The Company determined the long-term rate of                  however, management does not anticipate that the return based on historical asset class returns and current          liabilities, if any, arising from such current proceedings market conditions, taking into account the diversification         would have a material adverse effect on the Company's benefits of investing in multiple asset classes.                    financial statements.
An additional assumption used in measuring the                Retail Rate Orders accumulated postretirement benefit obligation was a On December 21, 2004, the Georgia PSC voted to weighted average medical care cost trend rate of 11.0 approve the 2004 Retail Rate Plan. Under the terms of percent for 2004, decreasing gradually to 5.0 percent the 2004 Retail Rate Plan, earnings will be evaluated through the year 2012, and remaining at that level against a retail return on common equity range of 10.25 thereafter. An annual increase or decrease in the percent to 12.25 percent. Two-thirds of any earnings assumed medical care cost trend rate of 1 percent would above 12.25 percent will be applied to rate refunds, with affect the accumulated benefit obligation and the service the remaining one-third retained by the Company.
and interest cost components at December 31, 2004, as Retail rates will be increased by approximately $194 follows:
million and customer fees by approximately $9 million effective January 1, 2005 to cover the higher costs of 1 Percent        1 Percent purchased power; operating and maintenance expenses; Increase        Decrease (inmillions)            environmental compliance; and continued investment in new generation, transmission and distribution facilities Benefit obligation                     $75              $59 to support growth and ensure reliability.
Service and interest costs                5               4 In the 2004 Retail Rate Plan, the Georgia PSC also Employee Savings Plan                                              approved the transfer of the Plant McIntosh construction project, which is scheduled for completion in June 2005, The Company also sponsors a 401(k) defined to the Company and Savannah Electric at a total fair contribution plan covering substantially all employees.
market value of approximately $385 million. This value 41

NOTES      (continued)
Georgia Power Company 2004 Annual Report reflects an approximate $16 million disallowance, of           PSC-certified PPAs evenly in rates over a three-year which $13 million is attributable to the Company, and          period ended December 31, 2004.
reduced the Company's 2004 net income by approximately $8 million. The Georgia PSC also                 Retail Fuel Hedging Program certified the total completion cost of $547 million for the project. The amount of the disallowance will be                Effective in January 2003, the Georgia PSC approved an adjusted accordingly based on the actual completion cost       order allowing the Company to implement a natural gas of the project. Under the 2004 Retail Rate Plan, the           and oil procurement and hedging program. This order Plant McIntosh revenue requirement impact will be              allows the Company to use financial instruments to reflected in the Company's rates evenly over the three         hedge price and commodity risk associated with these years ending 2007.                                             fuels. The order limits the program in terms of time, volume, dollars, and physical amounts hedged. The The Company will not file for a general base rate        costs of the program, including any net losses, are increase unless its projected retail return on common         recovered as a fuel cost through the fuel cost recovery equity falls below 10.25 percent. The Company is              clause. Annual net financial gains from the hedging required to file a general rate case by July 1, 2007, in       program will be shared with the retail customers response to which the Georgia PSC would be expected           receiving 75 percent and the Company retaining 25 to determine whether the rate order should be continued,       percent of the total net gains. In 2004, the Company had modified, or discontinued.                                    a total net gain of $7.4 million, of which the Company retained $1.9 million.
Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability           Fuel Cost Recovery account for use in meeting future environmental remediation costs. Under the 2004 Retail Rate Plan, this      On August 19, 2003, the Georgia PSC issued an order regulatory liability will be amortized over a three-year      allowing the Company to increase fuel rates to recover period beginning January 1, 2005. However, the                existing under recovered deferred fuel costs over the Georgia PSC also approved an annual environmental             period of October 1, 2003 through March 31, 2005, as accrual of $5.4 million. Environmental remediation             well as future projected fuel costs. The new fuel rate expenditures will be charged against the reserve as they       represented an average annual increase in rates paid by are incurred. The annual accrual amount will be                customers of approximately 1.6 percent. In recent reviewed and adjusted in future regulatory proceedings.        months, the Company has experienced higher than expected fuel costs since the order was issued. Those Under the 2001 Retail Rate Plan, retail rates were        higher fuel costs have increased the under recovered fuel decreased by $118 million effective January 1, 2002.           costs. On February 18, 2005, the Company filed a Under the terms of the 2001 Retail Rate Plan, earnings         request with the Georgia PSC for a fuel cost recovery were evaluated against a retail return on common equity       rate increase. In the ordinary course, these new rates range of 10 percent to 12.95 percent. Two-thirds of any        will be effective June 1, 2005 following a hearing before earnings above the 12.95 percent return were to be            and approval by the Georgia PSC. In its filing, the applied to rate refunds, with the remaining one-third         Company asked that the Georgia PSC accept the new retained by the Company. The Company's earnings in            rate, effective April 1, 2005, prior to a formal hearing on 2004, 2003 and 2002 were within the common equity             the Company's request. This action, if taken by the range.                                                        Georgia PSC, would serve to mitigate expected increases in the under recovered balance during April and May, Under the 2001 Retail Rate Plan, the Company             but will not preclude the Georgia PSC from discontinued recording accelerated depreciation and           subsequently adjusting the rates. The requested amortization and began amortizing the accumulated             increase, representing an annual increase in revenues of balance equally over three years as a credit to expense       approximately 11.7 percent, will allow for the recovery beginning in 2002. Also, the 2001 Retail Rate Plan            of fuel costs based on an estimate of future fuel costs, as required the Company to recognize capacity and                well as the collection of the existing under recovery of operating and maintenance costs related to new Georgia        fuel costs. The Company's under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia 42

NOTES     (continued)
Georgia Power Company 2004 Annual Report PSC will examine the Company's fuel expenditures and                Since the inception of the NSR proceedings against determine whether the proposed fuel cost recovery rate          the Company, the EPA has also been proceeding with is just and reasonable before issuing its decision in May       similar NSR enforcement actions against other utilities, 2005. The final outcome of the filing cannot be                 involving many of the same legal issues. In each case, determined at this time.                                        the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing Nuclear Performance Standards                                   maintenance and construction activities at coal-burning plants, which activities the utilities considered to be Through December 31, 2004, the Company has operated             routine or otherwise not subject to NSR. District courts in accordance with the nuclear performance standard the         addressing these cases have, to date, issued opinions that Georgia PSC adopted for the Company's nuclear                   reached conflicting conclusions.
generating units, under which the performance of plants Hatch and Vogtle is evaluated every three years. The                 The Company believes that it complied with performance standard is based on each unit's capacity           applicable laws and the EPA's regulations and factor as compared to the average of all comparable U.S.        interpretations in effect at the time the work in question nuclear units operating at a capacity factor of 50 percent      took place. The Clean Air Act authorizes maximum or higher during the three-year period of evaluation.           civil penalties of $25,000 to $32,500 per day, per Depending on the performance of the units, the                  violation at each generating unit, depending on the date Company could receive a monetary award or penalty               of the alleged violation. An adverse outcome in this under the performance standards criteria. Such amounts          matter could require substantial capital expenditures that flow through the fuel cost recovery mechanism. Any              cannot be determined at this time and could possibly award or penalty for the 2002-2004 evaluation period            require payment of substantial penalties. This could will not be known until the second quarter of 2005.             affect future results of operations, cash flows, and possibly financial condition if such costs are not Effective January 1, 2005, the Georgia PSC has             recovered through regulated rates.
discontinued the nuclear performance standard.
In December 2002 and October 2003, the EPA New Source Review Actions                                        issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included In November 1999, the Environmental Protection                   changes to the regulatory exclusions and the methods of Agency (EPA) brought a civil action in the U.S. District         calculating emissions increases. The October 2003 Court for the Northern District of Georgia against the          regulations clarified the scope of the existing Routine Company, alleging violations of the New Source Review            Maintenance, Repair, and Replacement (RMRR)
(NSR) provisions of the Clean Air Act and related state          exclusion. A coalition of states and environmental laws with respect to coal-fired generating facilities at the     organizations has filed petitions for review of these Company's Bowen and Scherer plants. The civil action             revisions with the U.S. Court of Appeals for the District requests penalties and injunctive relief, including an           of Columbia Circuit. The October 2003 RMRR rules order requiring the installation of the best available           have been stayed by the Court of Appeals pending its control technology at the affected units. The action            review of the rules. In any event, the final regulations against the Company was stayed in the spring of 2001             must be adopted by the State of Georgia in order to during the appeal of a similar NSR enforcement action            apply to the Company's facilities. The effect of these against the Tennessee Valley Authority (TVA) before             final regulations, related legal challenges and potential the U.S. Court of Appeals for the Eleventh Circuit. In           rulemakings by the State of Georgia cannot be June 2003, the Court of Appeals issued its ruling in the         determined at this time.
TVA case, dismissing the appeal for reasons unrelated to the issues in the case pending against the Company. In           Plant Wansley Environmental Litigation May 2004, the U.S. Supreme Court denied the EPA's petition for review of the case. At this time, no party to      On December 30, 2002, the Sierra Club, Physicians for the case against the Company has sought to reopen the            Social Responsibility, Georgia Forestwatch, and one case, which remains administratively closed in the U.S.         individual filed a civil suit in the U.S. District Court for District Court for the Northern District of Georgia.            the Northern District of Georgia against the Company for 43

NOTES     (continued)
Georgia Power Company 2004 Annual Report alleged violations of the Clean Air Act at four of the units      listed on the federal National Priorities List. The at Plant Wansley. The complaint alleges Clean Air Act             Company has contributed to the removal and remedial violations at both the existing coal-fired units and the new      investigation and feasibility study costs for the site.
combined cycle units. Specifically, the plaintiffs allege         Additional claims for recovery of natural resource (1) opacity violations at the coal-fired units, (2) violations    damages at the site are anticipated. As of December 31, of a permit provision that requires the combined cycle            2004, the Company had recorded approximately $6 units to operate above certain levels, (3) violation of           million in cumulative expenses associated with the nitrogen oxide emission offset requirements, and                  Company's agreed-upon share of the removal and (4) violation of hazardous air pollutant requirements. The        remedial investigation and feasibility study costs for the civil action requests injunctive and declaratory relief, civil    Brunswick site.
penalties, a supplemental environmental project, and attorneys' fees. The Clean Air Act authorizes civil                    The final outcome of these matters cannot now be penalties of up to $27,500, per day, per violation at each        determined. However, based on the currently known generating unit.                                                  conditions at these sites and the nature and extent of the Company's activities relating to these sites, management The court has concluded the liability phase of the           does not believe that the Company's additional liability, action. The court ruled in favor of the Company on the            if any, at these sites would be material to the financial allegations regarding the hazardous air pollutants, the           statements.
allegations regarding emission offsets, and a majority of the allegations regarding the permit provision that               Race Discrimination Litigation requires the combined cycle units to operate above certain levels. The court ruled in favor of the plaintiffs        In July 2000, a lawsuit alleging race discrimination on a majority of the opacity incidents. The Company               was filed by three of the Company's employees has filed a petition for review of the decision with the          against the Company, Southern Company, and SCS in U.S. Court of Appeals for the Eleventh Circuit. The               the Superior Court of Fulton County, Georgia.
district court case has been administratively closed              Shortly thereafter, the lawsuit was removed to the pending that appeal. If necessary, the district court will        U.S. District Court for the Northern District of hold a separate remedy trial which will address civil             Georgia. The lawsuit also raised claims on behalf of a penalties and possible injunctive relief requested by the         purported class. The plaintiffs seek compensatory plaintiffs. The ultimate outcome of this matter cannot            and punitive damages in an unspecified amount, as well as injunctive relief. In August 2000, the lawsuit currently be determined; however, an adverse outcome was amended to add four more plaintiffs. Also, an could require substantial capital expenditures that cannot        additional indirect subsidiary of Southern Company, be determined at this time and could possibly require the         Southern Company Energy Solutions, was named a payment of substantial penalties. This could affect               defendant.
future results of operations, cash flows, and possibly financial condition if such costs are not recovered                     In October 2001, the district court denied the through regulated rates.                                          plaintiffs' motion for class certification. The U.S.
Court of Appeals for the Eleventh Circuit Environmental Remediation                                         subsequently denied plaintiff's petition seeking permission to file an appeal of the October 2001 The Company has been designated as a potentially                  decision. In March 2003, the U.S. District Court for responsible party at sites governed by the Georgia                the Northern District of Georgia granted summary Hazardous Site Response Act and/or by the federal                 judgment in favor of the defendants on all claims Comprehensive Environmental Response,                             raised by all seven plaintiffs. In April 2003, plaintiffs Compensation, and Liability Act. The Company has                   filed an appeal to the U.S. Court of Appeals for the recognized $35 million in cumulative expenses through              Eleventh Circuit challenging these adverse summary December 31, 2004 for the assessment and anticipated              judgment rulings, as well as the District Court's cleanup of sites on the Georgia Hazardous Sites                   October 2001 ruling denying class certification. On Inventory. In addition, in 1995 the EPA designated the            November 10, 2004, a three-judge panel of the U.S.
Court of Appeals for the Eleventh Circuit issued an Company and four other unrelated entities as potentially order affirming in all respects the district court's responsible parties at a site in Brunswick, Georgia that is 44

NOTES (continued)
Georgia Power Company 2004 Annual Report rulings. On December 1, 2004, the plaintiffs filed a         contractually obligated to indemnify, defend, and hold petition for rehearing seeking a review of the               harmless the telecommunications company from any November 2004 order by the entire Eleventh Circuit           liability that may be assessed against it in pending and panel of judges. If this petition is denied, the             future right of way litigation. The Company believes plaintiffs will have 90 days from the date of the            that the plaintiff's claims are without merit. In the fall court's order denying the petition within which to file      of 2004, the trial court stayed the case until resolution a petition for writ of certiorari to the U.S. Supreme        of the underlying landowner litigation discussed Court. The final outcome of this matter cannot now           above. On January 12, 2005, the Georgia Court of be determined.                                               Appeals dismissed the telecommunications company's appeal of the trial court's order for lack of Right of Way Litigation                                      jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the Southern Company and certain of its subsidiaries,            telecommunications company in one or more of the including the Company, Gulf Power, Mississippi               right of way lawsuits, could result in substantial Power, and Southern Telecom, have been named as              judgments; however, the final outcome of these defendants in numerous lawsuits brought by                   matters cannot now be determined.
landowners since 2001. The plaintiffs' lawsuits claim that defendants may not use, or sublease to third            Generation Interconnection Agreements parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs'        In July 2003, the FERC issued its final rule on the properties and that such actions exceed the easements        standardization of generation interconnection or other property rights held by defendants. The             agreements and procedures (Order 2003). Order 2003 plaintiffs assert claims for, among other things,            shifts much of the financial burden of new trespass and unjust enrichment, and seek                     transmission investment from the generator to the compensatory and punitive damages and injunctive             transmission provider. The FERC has indicated that relief.                                                       Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection On January 14, 2005, the Superior Court of              agreements. Subsidiaries of Tenaska, Inc., as Decatur County, Georgia granted partial summary              counterparties to previously executed interconnection judgment in a lawsuit brought by landowners against           agreements with the Company and another Southern the Company based on the plaintiffs' declaratory             Company subsidiary, have filed complaints at the judgment claim that the easements do not permit               FERC requesting that the FERC modify the general telecommunications use. The Company is               agreements and that the Company refund a total of appealing this ruling to the Georgia Court of Appeals.       $7.9 million previously paid for interconnection The question of damages and other liabilities or             facilities, with interest. The Company has opposed remedies issues with respect to this action, if any, will    such relief and the proceedings are still pending. The be decided at a future trial. In the event of an adverse     impact of Order 2003 and its subsequent rehearings verdict in the case, the Company could appeal both           on the Company and the final results of these matters liability and damages or other relief granted.               cannot be determined at this time.
Management believes that the Company has complied with applicable laws and that the plaintiffs' claims are     Market-Based Rate Authority without merit. An adverse outcome in these matters could result in substantial judgments; however, the          The Company has authorization from the FERC to final outcome cannot now be determined.                      sell power to nonaffiliates at market-based prices.
Through SCS, as agent, the Company also has FERC In addition, in late 2001, certain subsidiaries of      authority to make short-term opportunity sales at Southern Company, including Alabama Power, the               market rates. Specific FERC approval must be Company, Gulf Power, Mississippi Power, Savannah             obtained with respect to a market-based contract with Electric, and Southern Telecom, were named as                an affiliate. In November 2001, the FERC modified defendants in a lawsuit brought by a                         the test it uses to consider utilities' applications to telecommunications company that uses certain of the          charge market-based rates and adopted a new test defendants' rights of way. This lawsuit alleges,             called the Supply Margin Assessment (SMA). The among other things, that the defendants are                  FERC applied the SMA to several utilities, including 45

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Georgia Power Company 2004 Annual Report Southern Company, the retail operating companies,                  In the event that the FERC's default mitigation and Southern Power and found them to be "pivotal              measures are ultimately applied, the Company may be suppliers" in their retail service territories and ordered    required to charge cost-based rates for certain the implementation of certain mitigation measures.            wholesale sales in the Southern Company retail Southern Company and others sought rehearing of the           service territory, which may be lower than negotiated FERC order, and the FERC delayed implementation               market-based rates. The final outcome of this matter of certain mitigation measures. In April 2004, the            will depend on the form in which the final FERC issued an order that abandoned the SMA test              methodology for assessing generation market power and adopted a new interim analysis for measuring              and mitigation rules may be ultimately adopted and generation market power. This new interim approach            cannot be determined at this time.
requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant         Plant McIntosh Construction Project does not pass both screens, there will be a rebuttable presumption regarding generation market power. The            In December 2002 after a competitive bidding FERC's order also sets forth procedures for rebutting         process, the Georgia PSC certified PPAs between these presumptions and addresses mitigation measures          Southern Power and the Company and Savannah for those entities that are found to have market power.       Electric for capacity from Plant McIntosh Units 10 In the absence of specific mitigation measures, the           and 11, construction of which is scheduled to be order includes several cost-based mitigation measures         completed in June 2005. In April 2003, Southern that would apply by default. The FERC also initiated          Power applied for FERC approval of these PPAs. In a new rulemaking proceeding that, among other                 July 2003, the FERC accepted the PPAs to become things, will adopt a final methodology for assessing          effective June 1, 2005, subject to refund, and ordered generation market power.                                      that hearings be held. Intervenors opposed the FERC's acceptance of the PPAs, alleging that they In July 2004, the FERC denied Southern                   did not meet the applicable standards for market-Company's request for rehearing, along with a                 based rates between affiliates. To ensure the timely number of others, and reaffirmed the interim tests that       completion of the Plant McIntosh construction project it adopted in April. In August 2004, Southern                 and the availability of the units in the summer of 2005 Company submitted a filing to the FERC which                  for their retail customers, in May 2004, the Company included results showing that Southern Company                and Savannah Electric requested the Georgia PSC to passed the pivotal supplier screen for all markets and        direct them to acquire the McIntosh construction the wholesale market share screen for all markets             project. The Georgia PSC issued such an order and except the Southern Company retail service territory.         the transfer occurred on May 24, 2004 at a total cost Southern Company also submitted other analyses to             of approximately $415 million, including demonstrate that it lacks generation market power.            approximately $14 million of transmission On December 17, 2004, the FERC initiated a                    interconnection facilities. Subsequently, Southern proceeding to assess Southern Company's generation            Power filed a request to withdraw the PPAs and to dominance within the Southern Company retail                  terminate the ongoing FERC proceedings. In August service territory. The ability to charge market-based         2004, the FERC issued a notice accepting the request rates in other markets is not at issue. As directed by        to withdraw the PPAs and permitting such request to this order, on February 15 2005, Southern Company             become effective by operation of law. However, the submitted additional information related to generation        FERC made no determination on what additional dominance in the retail service territory. Any new            steps may need to be taken with respect to testimony market-based rate transactions in Southern                    provided in the proceedings. The ultimate outcome of Company's retail service territory entered into after         any additional FERC action cannot be determined at February 27, 2005 will be subject to refund to the            this time.
level of the default cost-based rates, pending the outcome of the proceeding. Southern Company,                       As directed by the Georgia PSC order, on June 3, along with other utilities, has also filed an appeal of       2004, the Company and Savannah Electric filed an the FERC's April and July 2004 orders with the U.S.           application to amend the resource certificate granted Court of Appeals for the District of Columbia Circuit.        by the Georgia PSC in 2002. In connection with the The FERC has asked the court to dismiss the appeal            2004 Retail Rate Plan, the Georgia PSC approved the on the grounds that it is premature.                          transfer of the Plant McIntosh construction project at 46

NOTES      (continued)
Georgia Power Company 2004 Annual Report a total fair market value of approximately $385                 turbine units with Savannah Electric who operates the million. This value reflects an approximate                     plant. The Company and Florida Power Corporation
 $16 million disallowance, of which $13 million is               (FPC) jointly own a combustion turbine unit attributable to the Company, and reduced the                    (Intercession City) operated by FPC.
Company's net income by approximately $8 million.
The Georgia PSC also certified a total completion                    At December 31, 2004, the Company's percentage cost of $547 million for the project. The amount of             ownership and investment (exclusive of nuclear fuel) in the disallowance will be adjusted accordingly based            jointly owned facilities in commercial operation were as on the actual completion cost of the project. Under follows:
the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact will be reflected in the Company's rates evenly over the three years ending Facility (Type)            Company                     Accumulated 2007. See "Retail Rate Orders" herein for additional                                      Ownership    Investment      Depreciation information regarding the transfer of the Plant                                                                (in millions)
McIntosh construction project.                                  Plant Vogtle (nuclear)       45.7%       $3,304*         $1,756 Plant Hatch (nuclear)        50.1           932              485
: 4. JOINT OWNERSHIP AGREEMENTS                                   Plant Wansley (coal)          53.5           394              164 Plant Scherer (coal)
The Company and an affiliate, Alabama Power, own                     Units I and 2            8.4           114               53 equally all of the outstanding capital stock of SEGCO               Unit 3                   75.0           561              259 which owns electric generating units with a total rated         Plant McIntosh capacity of 1,020 megawatts, as well as associated                Common Facilities transmission facilities. The capacity of the units has               (combustion-turbine)     75.0            34                4 been sold equally to the Company and Alabama Power              Rocky Mountain                25.4           169*              89 under a contract which, in substance, requires payments             (pumped storage) sufficient to provide for the operating expenses, taxes,        Intercession City (combustion-turbine)      33.3            12                2 debt service, and return on investment, whether or not SEGCO has any capacity and energy available. The                *Investment includes write-offs term of the contract extends automatically for two-year periods, subject to either party's right to cancel upon two           The Company has contracted to operate and year's notice. The Company's share of expenses                  maintain the jointly owned facilities as agent for their included in purchased power from affiliates in the              co-owners, except as noted above. The Company's statements of income is as follows:                             proportionate share of its plant operating expenses is included in the corresponding operating expenses in the 2004           2003     2002            statements of income.
(in millions)
Energy                  $51             $55     $53            5. INCOME TAXES Capacity                 36              34       32 Total                   $87             $89     $85            Southern Company and its subsidiaries file a consolidated federal income tax return and a combined The Company owns undivided interests in plants            State of Georgia income tax return. Under a joint Vogtle, Hatch, Scherer, and Wansley in varying amounts          consolidated income tax allocation agreement, as jointly with Oglethorpe Power Corporation (OPC), the            required by the PUHCA, each subsidiary's current and Municipal Electric Authority of Georgia (MEAG), the             deferred tax expense is computed on a stand-alone basis city of Dalton, Georgia, Florida Power & Light                  and no subsidiary is allocated more expense than would Company, Jacksonville Electric Authority, and Gulf              be paid if they filed a separate tax return. In accordance Power. Under these agreements, the Company is jointly           with IRS regulations, each company is jointly and and severally liable for third party claims related to these    severally liable for the tax liability.
plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant                     In 2004, in order to avoid the loss of certain federal with OPC who is the operator of the plant. The                  income tax credits related to the production of synthetic Company also jointly owns Plant McIntosh combustion-            fuel, Southern Company chose to defer certain 47

NOTES      (continued)
Georgia Power Company 2004 Annual Report deductions otherwise available to the subsidiaries. The                  Details of the federal and state income tax provisions cash flow benefit associated with the utilization of the          are as follows:
tax credits was allocated to the subsidiary that otherwise                                            2004       2003        2002 would have claimed the available deductions on a                     Total provision for income taxes:       (in millions) separate company basis without the deferral. This                     Federal:
allocation concurrently reduced the tax benefit of the                  Current                       $116       $143      $261 credits allocated to those subsidiaries that generated the              Deferred                        221        181         60 credits. As the deferred expenses are deducted, the                                                     337       324        321 benefit of the tax credits will be repaid to the                      State:
subsidiaries that generated the tax credits. The                        Current                          12         24         31 Company has recorded $25 million payable to these                       Deferred                         30         16           5 subsidiaries in Accumulated Deferred Income Taxes on                    Deferred investment tax credits                        -          2          -
the balance sheets at December 31, 2004.
Total                            $379      $366       $357 The transfer of the Plant McIntosh construction project from Southern Power to the Company resulted in                  The tax effects of temporary differences between the a deferred gain to Southern Power for federal income tax         carrying amounts of assets and liabilities in the financial purposes. The Company will reimburse Southern Power              statements and their respective tax bases, which give rise for the related $5.4 million deferred taxes reflected in         to deferred tax assets and liabilities, are as follows:
Southern Power's future taxable income. This payable to Southern Power is included in Other Deferred Credits                                                           2004          2003 (in millions) on the balance sheets at December 31, 2004.
Deferred tax liabilities:
The transfer of the Dahlberg, Wansley and Franklin               Accelerated depreciation                 $2,050        $1,966 projects to Southern Power from the Company in 2001                    Property basis differences                  577            563 and 2002 also resulted in a deferred gain for federal             -
Other                                       449            329 income tax purposes. Southern Power will reimburse                   Total                                       3,076          2,858 the Company for the remaining balance of the related                 Deferred tax assets:
deferred taxes of $13.3 million reflected in the                       Federal effect of state deferred taxes      106              96 Company's future taxable income. This receivable from                  Other property basis differences            147             156 Southern Power is included in Other Deferred Debits on                 Other deferred costs                        149             160 the balance sheets at December 31, 2004.                               Other                                         52             75 Total                                        454             487 At December 31, 2004, tax-related regulatory assets             Net deferred tax liabilities               2,622          2,371 were $506 million and tax-related regulatory liabilities             Portion included in current were $171 million. The assets are attributable to tax                   (liabilities) assets, net                  (66)            68 benefits flowed through to customers in prior years and              Accumulated deferred income taxes to taxes applicable to capitalized interest. The liabilities           in the balance sheets                   $2,556         $2,439 are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to                      In accordance with regulatory requirements, deferred unamortized investment tax credits.                                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
                                                                     $12 million in 2004, $15 million in 2003, and $12 million in 2002. At December 31, 2004, all investment tax credits available to reduce federal income taxes payable had been utilized.
48

NOTES       (continued)
Georgia Power Company 2004 Annual Report A reconciliation of the federal statutory tax rate to      $153 million in 2006; $303 million in 2007; $3 million the effective income tax rate is as follows:                      in 2008; and $279 million in 2009.
2004       2003        2002      Pollution Control Bonds Federal statutory rate             35%         35%         35%
State income tax, net of                                          Pollution control obligations represent loans to the federal deduction             3            3           2    Company from public authorities of funds derived from Non-deductible book                                               sales by such authorities of revenue bonds issued to depreciation                   1           1           1    finance pollution control facilities. The Company is Other                                                             required to make payments sufficient for the authorities Effective income tax rate          37%          37%        37%    to meet principal and interest requirements of such bonds. The Company has incurred obligations in
: 6. FINANCING                                                      connection with the sale by public authorities of tax-exempt pollution control revenue bonds. The amount of Mandatorily Redeemable Preferred Securities/Long-                 tax-exempt pollution control revenue bonds outstanding Term Debt Payable to Affiliated Trusts                            at December 31, 2004 was $1.7 billion.
The Company has formed certain wholly-owned trust                 Capital Leases subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity                    Assets acquired under capital leases are recorded in the investments and preferred security sales were loaned              balance sheets as utility plant in service, and the related back to the Company through the issuance of junior                obligations are classified as long-term debt. At subordinated notes totaling $969 million, which                  December 31, 2004 and 2003, the Company had a constitute substantially all of the assets of the trusts and      capitalized lease obligation for its corporate headquarters are reflected in the balance sheets as Long-Term Debt            building of $77 million and $79 million, respectively, Payable to Affiliated Trusts. The Company considers              with an interest rate of 8.1 percent. For ratemaking that the mechanisms and obligations relating to the              purposes, the Georgia PSC has treated the lease as an preferred securities issued for its benefit, taken together,      operating lease and has allowed only the lease payments constitute a full and unconditional guarantee by it of the        in cost of service. The difference between the accrued respective trusts' payment obligations with respect to            expense and the lease payments allowed for ratemaking these securities. At December 31, 2004, preferred                purposes has been deferred and is being amortized to securities of $940 million were outstanding. See Note I           expense as ordered by the Georgia PSC. At December under "Variable Interest Entities" for additional                 31, 2004 and 2003, the interest and lease amortization information on the accounting treatment for these trusts          deferred on the balance sheets were $53 million and $54 and the related securities. The preferred securities are          million, respectively.
recognized as liabilities in the balance sheets.
Bank Credit Arrangements Long-Term Debt Due Within One Year At the beginning of 2005, the Company had an unused A summary of the scheduled maturities and redemptions             credit arrangement with banks totaling $773.1 million.
of securities due within one year at December 31 is as            Of these facilities, $423.1 million expire at various times follows:                                                          throughout 2005, with the remaining $350 million expiring in 2007. The facilities that expire in 2005 2004           2003      provide the option of converting borrowings into a two-(in millions)         year term loan. The agreements contain stated Capital lease                         $    2            $2     borrowing rates but also allow for competitive bid loans.
Senior notes                            450                    All the agreements require payment of commitment fees based on the unused portion of the commitments or the Total                                 $452              $2 maintenance of compensating balances with the banks.
Serial maturities through 2009 applicable to total         Commitment fees are less than 1/8 of 1 percent for the long-term debt are as follows: $452 million in 2005;            Company. Compensating balances are not legally 49

NOTES     (continued)
Georgia Power Company 2004 Annual Report restricted from withdrawal. A fee is also paid to the             At December 31, 2004, the fair value of derivative agent bank.                                                   energy contracts was reflected in the financial statements as follows:
The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent,                                                Amounts as defined in the arrangements. For purposes of these                                                    (in millions) definitions, indebtedness excludes the long-term debt         Regulatory liabilities, net                    $5.7 payable to affiliated trusts. In addition, the credit         Other comprehensive income arrangements contain cross default provisions that would      Net income                                      0.1 trigger an event of default if the Company defaulted on       Total fair value                               $5.8 other indebtedness above a specified threshold. The Company is currently in compliance with all such                   The fair value gain or loss for cash flow hedges that covenants.                                                    are recoverable through the regulatory fuel clauses are recorded in regulatory assets and liabilities and are This $773.1 million in unused credit arrangements        recognized in earnings at the same time the hedged items provides liquidity support to the Company's variable          affect earnings. The Company has energy-related rate pollution control bonds. The amount of variable          hedges in place up to and including 2007.
rate pollution control bonds outstanding requiring liquidity support as of December 31, 2004 was $106                 The Company enters into derivatives to hedge million. In addition, the Company borrows under a             exposure to interest rate changes. Derivatives related to commercial paper program and an extendible                    variable rate securities or forecasted transactions are commercial note program. The amount of commercial             accounted for as cash flow hedges. The derivatives are paper outstanding at December 31, 2004 was $208               generally structured to mirror the critical terms of the million. There were no outstanding extendible                 hedged debt instruments; therefore, no material commercial notes at December 31, 2004. The amount of          ineffectiveness has been recorded in earnings. In commercial paper outstanding at December 31, 2003             addition to interest rate swaps, the Company has also was $137 million. During 2004, the peak amount of             entered into certain options agreements that effectively commercial paper outstanding was $391.5 million and           cap its interest rate exposure in return for payment of a the average amount outstanding was $130.7 million.            premium. In some cases, costless collars have been used The average annual interest rate on commercial paper in       that effectively establish a floor and a ceiling to interest 2004 was 1.27 percent. Commercial paper is included in        rate expense.
notes payable on the balance sheets.
Financial Instruments The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the instruction of the Georgia PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2004 and 2003.
50

NOTES (continued)
Georgia Power Company 2004 Annual Report At December 31, 2004, the Company had interest                            commitments for uranium and nuclear fuel conversion, derivatives outstanding with net fair value losses as                           enrichment, and fabrication services included under follows:                                                                        "Fuel Commitments." The construction program is subject to periodic review and revision, and actual Cash Flow Hedges                                                                construction costs may vary from estimates because of numerous factors, including, but not limited to, changes Weighted                                             in business conditions, changes in FERC rules and Average                              Fair           transmission regulations, revised load growth estimates, Fixed                            Value            changes in environmental regulations, changes in Rate           Notional         Gain/            existing nuclear plants to meet new regulatory Maturity
=.        ,
Paid           Amount           (Loss)          requirements, increasing costs of labor, equipment, and (in millions)               materials, and cost of capital. At December 31, 2004, 2005                        1.56%             $50            $0.1           significant purchase commitments were outstanding in 2005                        1.96              250              0.3          connection with the construction program.
2005-2007                   2.35-3.85' '       400              0.6 2006                         6.002             150             (0.1)              The Company currently has under construction Plant 2015                        4.66               250              0.7          McIntosh Units 10 and 11 scheduled for completion in 2015                         5.03              100             (0.9)         June 2005. In addition, construction related to new
: 1. Capped rate based on formula approximating the yield on short rate transmission and distribution facilities and capital tax-exempt, auction rate securities.                                  improvements to existing generation, transmission and
: 2. Costless collar with cap rate of 6.00 percent.                        distribution facilities, including those needed to meet environmental standards, are ongoing.
The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is                                   Long-Term Service Agreements reclassified into earnings at the same time the hedged items affect earnings. In 2004, the Company settled                             The Company and Savannah Electric have entered losses totaling $12.4 million upon termination of certain                      into a Long-Term Service Agreement (LTSA) with interest derivatives at the same time it issued debt. For                       General Electric (GE) for the purpose of securing the years 2004 and 2003, approximately $3.9 million and                         maintenance support for the combustion turbines at
$3.4 million, respectively, were reclassified from other                        the Plant McIntosh combine cycle facility. In comprehensive income to interest expense. For 2002,                             summary, the LTSA stipulates that GE will perform the amounts reclassified were immaterial. For 2005,                             all planned inspections on the covered equipment, pre-tax losses of approximately $0.4 million are                                which includes the cost of all labor and materials. GE expected to be reclassified from other comprehensive                            is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a income to interest expense. The Company has interest-limit specified in each contract.
related hedges in place through 2017. Subsequent to December 31, 2004, the Company terminated an interest                                In general, this LTSA is in effect through two rate swap with a notional amount of $250 million at a                           major inspection cycles per unit. Scheduled payments gain of $1.2 million. The gain will be amortized to                             to GE are made at various intervals based on actual interest expense over a 10-year period.                                         operating hours of the respective units. Total payments to GE under this agreement are currently
: 7. COMMITMENTS                                                                  estimated at $182 million over the remaining term of the agreement, which may range up to 30 years.
Construction Program                                                            However, the LTSA contains various cancellation provisions at the option of the Company.
The Company currently estimates property additions to be approximately $911 million, $ 1.1 billion, and $1.2                               The Company has entered into a LTSA with GE billion in 2005, 2006, and 2007, respectively. These                            to provide all necessary labor and parts for neutron amounts include $40 million, $33 million, and $28                               monitoring at Plant Hatch for a period of 10 years.
million in 2005, 2006, and 2007, respectively, for                              Total payments to GE under this agreement are construction expenditures related to contractual purchase                       currently estimated at $14.9 million, of which $7.4 is 51

NOTES      (continued)
Georgia Power Company 2004 Annual Report expected to be billed to the joint owners.                    or Southern Company GAS as a contracting party under these agreements.
Fuel Commitments Purchased Power Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various       The Company has commitments regarding a portion of a long-term commitments for the procurement of fossil           5 percent interest in Plant Vogtle owned by MEAG that and nuclear fuel. In most cases, these contracts contain      are in effect until the latter of the retirement of the plant provisions for price escalations, minimum purchase            or the latest stated maturity date of MEAG's bonds levels, and other financial commitments. Natural gas          issued to finance such ownership interest. The payments purchase commitments contain fixed volumes with               for capacity are required whether or not any capacity is prices based on various indices at the time of delivery.      available. The energy cost is a function of each unit's Amounts included in the chart below represent estimates       variable operating costs. Except as noted below, the cost based on New York Mercantile Exchange future prices           of such capacity and energy is included in purchased at December 31, 2004. Also the Company has entered            power from non-affiliates in the Company's statements into various long-term commitments for the purchase of        of income. Capacity payments totaled $55 million, $57 electricity. Total estimated minimum long-term                million, and $57 million in 2004, 2003, and 2002, obligations at December 31, 2004 were as follows:             respectively. The current projected Plant Vogtle capacity payments are:
Coal and Year                          Natural         Nuclear       Year                              Capacity Payments Gas             Fuel                                                 (in millions)
(in millions)            2005                                        $ 56 2005                        $ 2418            $1,731        2006                                            55 2006                              17            1,617       2007                                           54 2007                           1 6i1            1,105       2008                                            54 2008                           2(00               552                                                       54 2009 2009                           1809               219 2010 and thereafter                          315 2010 and thereafter          1,6(69                96 Total                                       $588 Total commitments           $206  94          $5,320 Additional commitments for coal and for nuclear              Portions of the payments noted above relate to costs in excess of Plant Vogtle's allowed investment for fuel will be required to supply the Company's future ratemaking purposes. The present value of these needs.
portions at the time of the disallowance was written off.
SCS may enter into various types of wholesale The Company has entered into other various long-energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company             term commitments for the purchase of electricity.
retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies.
Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power 52

NOTES      (continued)
Georgia Power Company 2004 Annual Report Estimated total long-term obligations at December          related to the rail car leases are fully recoverable through 31, 2004 were as follows:                                       the fuel cost recovery clause as ordered by the Georgia PSC.
Non-Year                        Affiliated          Affiliated      Guarantees (in millions) 2005                        $ 205                $ 78           Prior to 1999, a subsidiary of Southern Company 2006                            205                 86          originated loans to residential customers of the Company 2007                            205                 87          for heat pump purchases. These loans were sold to 2008                            205                 88          Fannie Mae with recourse for any loan with payments 2009                            205                 67          outstanding over 120 days. The Company is responsible 2010 and thereafter             567                340          for the repurchase of customers' delinquent loans. As of Total                        $1,592              $746           December 31, 2004, the outstanding loans guaranteed by the Company were $5.1 million and loan loss reserves of Operating Leases                                                $ 1.1 million have been recorded.
The Company has entered into various operating leases                Alabama Power has guaranteed unconditionally the with various terms and expiration dates. Rental                 obligation of SEGCO under an installment sale expenses related to these operating leases totaled $38          agreement for the purchase of certain pollution control million for 2004, $36 million for 2003, and $35 million         facilities at SEGCO's generating units, pursuant to for 2002. At December 31, 2004, estimated minimum               which $24.5 million principal amount of pollution rental commitments for these noncancelable operating            control revenue bonds are outstanding. The Company leases were as follows:                                         has agreed to reimburse Alabama Power for the pro rata portion of such obligation corresponding to the Company's then proportionate ownership of stock of Minimum Obligations                 SEGCO if Alabama Power is called upon to make such Year                   Rail Cars         Other         Total    payment under its guaranty. In May 2003, SEGCO (in millions)                issued an additional $50 million in senior notes.
2005                      $ 15            $17         $ 32      Alabama Power guaranteed the debt obligation and in 2006                         16              13          29     October 2003, the Company agreed to reimburse 2007                         13              10          23     Alabama Power for the pro rata portion of such 2008                         14               8          22     obligation corresponding to its then proportionate 2009                         13               7          20     ownership of stock of SEGCO if Alabama Power is 2010 and                                                        called upon to make such payment under its guaranty.
thereafter                   55               8          63 Total                     $126            $63         $189           As discussed earlier in this note under "Operating Leases," the Company has entered into certain residual In addition to the rental commitments above, the           value guarantees related to rail car leases.
Company has obligations upon expiration of certain rail car leases with respect to the residual value of the leased     8. STOCK OPTION PLAN property. These leases expire in 2011, and the Company's maximum obligation is $72 million. At the             Southern Company provides non-qualified stock options termination of the leases, at the Company's option, the         to a large segment of its employees ranging from line Company may either exercise its purchase option or the          management to executives. As of December 31, 2004, property can be sold to a third party. The Company              1,547 current and former employees of the Company expects that the fair market value of the leased property       participated in the stock option plan. The maximum would substantially reduce or eliminate the Company's           number of shares of Southern Company common stock payments under the residual value obligation. A portion         that may be issued under this plan may not exceed 55 of the rail car lease obligations is shared with the joint      million. The prices of options granted to date have been owners of plants Scherer and Wansley. Rental expenses           at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro 53

NOTES      (continued)
Georgia Power Company 2004 Annual Report rata over a maximum period of three years from the date              third-party liability arising from any nuclear incident of grant. Options outstanding will expire no later than              occurring at the Company's nuclear power plants. The 10 years after the date of grant, unless terminated earlier          act provides funds up to $10.76 billion for public by the Southern Company Board of Directors in                        liability claims that could arise from a single nuclear accordance with the stock option plan. Activity from                 incident. Each nuclear plant is insured against this 2002 to 2004 for the options granted to the Company's                liability to a maximum of $300 million by American employees under the stock option plan is summarized                  Nuclear Insurers (ANI), with the remaining coverage below:                                                               provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against Shares        Average       all owners of nuclear reactors. The Company could be Subject Option Price          assessed up to $101 million per incident for each To Option       Per Share      licensed reactor it operates but not more than an Balance at December     31, 2001 6,597,517              $17.41       aggregate of $10 million per incident to be paid in a Options granted                       1,781,940          25.27       calendar year for each reactor. Such maximum Options canceled                         (40,607)        16.67       assessment for the Company, excluding any applicable Options exercised                   (1,160,253)          15.18       state premium taxes -- based on its ownership and Balance at December     31, 2002 7,178,597               19.73       buyback interests -- is $203 million per incident but not Options granted                       1,455,517          27.98       more than an aggregate of $20 million to be paid for Options canceled                         (54,860)        25.47       each incident in any one year. The Price-Anderson Options exercised                   (1,428,273)          16.92 Amendments Act expired in August 2002; however, the Balance at December     31, 2003 7,150,981               21.92 indemnity provisions of the Act remain in place for Options granted                      1,434,915           29.50 Options canceled                          (5,802)        25.99       commercial nuclear reactors.
Options exercised                   (1,450,309)          18.25 Balance at December     31, 2004 7,129,785             $24.19             The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up Options exercisable:                                                 to $500 million for members' nuclear generating At December 31, 2002               3,405,398                       facilities.
At December 31, 2003               3,956,234 At December 31, 2004               4,304,091                            Additionally, the Company has policies that currently provide decontamination, excess property The following table summarizes information about                insurance, and premature decommissioning coverage up options outstanding at December 31, 2004:                            to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also Dollar Price            provided by NEIL.
Range of Options 13-20       20-26 26-32              NEIL also covers additional costs that would be Outstanding:                                                         incurred in obtaining replacement power during a Shares (in thousands)             1,914       2,411     2,805     prolonged accidental outage at a member's nuclear plant.
Average remaining Members can purchase this coverage, subject to a life (in years)                    5.6        6.8       8.6 Average exercise price          $17.42       $24.26 $28.76        deductible waiting period of up to 26 weeks, with a Exercisable:                                                         maximum per occurrence per unit limit of $490 million.
Shares (in thousands)             1,914       1,906       483     After this deductible period, weekly indemnity payments Average exercise price          $17.42       $23.99 $28.01        would be received until either the unit is operational or until the limit is exhausted in approximately three years.
: 9. NUCLEAR INSURANCE                                                 The Company purchases the maximum limit allowed by NEIL subject to ownership limitations and has elected a Under the Price-Anderson Amendments Act of 1988, the                  12 week waiting period.
Company maintains agreements of indemnity with the NRC that, together with private insurance, cover                          Under each of the NEIL policies, members are subject to assessments if losses each year exceed the 54

NOTES (continued)
Georgia Power Company 2004 Annual Report accumulated funds available to the insurer under that          10. QUARTERLY FINANCIAL INFORMATION policy. The current maximum annual assessments for                  (UNAUDITED) the Company under the NEIL policies would be $43 million.                                                       Summarized quarterly financial information for 2004 and 2003 is as follows:
Following the terrorist attacks of September 2001,                                                         Net Income both ANI and NEIL confirmed that terrorist acts against                                                            After commercial nuclear power stations would be covered                                                             Dividends on under their insurance. Both companies, however,                                     Operating   Operating        Preferred revised their policy terms on a prospective basis to             Quarter Ended      Revenues     Income            Stock (in millions) include an industry aggregate for all "non-certified" terrorist acts (i.e., acts that are not certified acts of      March 2004            $1,199       $285            $144 terrorism pursuant to the Terrorism Risk Insurance Act         June 2004               1,353        322            156 of 2002 (TRIA). The NEIL aggregate -- applies to non-          September 2004          1,582        486            287 certified claims stemming from terrorism within a 12-          December 2004           1,237        166              71 month duration -- is $3.24 billion plus any amounts available through reinsurance or indemnity from an             March 2003            $1,126       $262            $133 outside source. The non-certified ANI cap is a $300            June 2003               1,190        293            159 million shared industry aggregate. Any act of terrorism        September 2003          1,487        490            265 that is certified pursuant to the TRIA will not be subject     December 2003           1,111        179              74 to the foregoing NEIL and ANI limitations but will be subject to the TRIA annual aggregate limitation of $100            The Company's business is influenced by seasonal billion of insured losses arising from certified acts of       weather conditions.
terrorism. The TRIA will expire on December 31, 2005.
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.
55

SELECTED FINANCIAL AND OPERATING DATA 2000-2004 Georgia Power Company 2004 Annual Report 2004          2003          2002         2001         2000 Operating Revenues (in thousands)              $5,370,808     $4,913,507    $4,822,460   $4,965,794   $4,870,618 Net Income after Dividends on Preferred Stock (in thousands)              $658,001       $630,577      $617,629     $610,335     $559,420 Cash Dividends on Common Stock (in thousands)                 $565,500       $565,800      $542,900     $527,300     $549,600 Return on Average Common Equity (percent)            13.95          14.05         13.99        14.12        13.66 Total Assets (in thousands)                   $15,822,338    $14,850,754   $14,342,656 $14,447,973   $13,971,211 Gross Property Additions (in thousands)        $1,126,064       $742,810      $883,968   $1,389,751   $1,078,163 Capitalization (in thousands):
Common stock equity                            $4,890,561     $4,540,211    $4,434,447   $4,397,485   $4,249,544 Preferred stock                                     14,609        14,569        14,569       14,569        14,569 Mandatorily redeemable preferred securities                -     940,000       940,000      789,250      789,250 Long-term debt payable to affiliated trusts       969,073             -             -            -             -
Long-term debt                                  3,709,852      3,762,333     3,109,619    2,961,726    3,041,939 Total (excluding amounts due within one year)  $9,584,095     $9,257,113    $8,498,635   $8,163,030   $8,095,302 Capitalization Ratios (percent):
Common stock equity                                    51.0          49.0          52.2         53.9         52.5 Preferred stock                                         0.2            0.2           0.2         0.2           0.2 Mandatorily redeemable preferred securities             -            10.2          11.1          9.6           9.7 Long-term debt payable to affiliated trusts            10.1           -             -            -             -
Long-term debt                                        38.7           40.6          36.5         36.3         37.6 Total  (excluding amounts due within oneyear)        100.0          100.0         100.0        100.0        100.0 Security Ratings:
Preferred Stock -
Moody's                                          Baal           Baal          Baal         Baal              a2 Standard and Poor's                             BBB+           BBB+          BBB+         BBB+         BBB+
Fitch                                                 A             A             A            A              A Unsecured Long-Term Debt -
Moody's                                             A2             A2            A2          A2            A2 Standard and Poor's                                  A             A             A            A              A Fitch                                              A+             A+           A+           A+            A+
Customers       (year-end):
Residential                                     1,801,426      1,768,662     1,734,430    1,698,407    1,669,566 Commercial                                        265,543        258,276       250,993      244,674      237,977 Industrial                                           7,676          7,899         8,240       8,046         8,533 Other                                                3,482         3,434         3,328        3,239         3,159 Total                                           2,078,127      2,038,271     1,996,991    1,954,366    1,919,235 Employees (year-end):                                8,731          8,714         8,837       9,048         8,860 N/A = Not Applicable.
56

SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Georgia Power Company 2004 Annual Report 2004        2003        2002        2001          2000 Operating Revenues       (in thousands):
Residential                                $ 1,736,072   $1,583,082  $1,600,438  $1,507,031   $1,535,684 Commercial                                   1,812,096    1,661,054   1,631,130   1,682,918    1,620,466 Industrial                                   1,172,936    1,012,267   1,004,288   1,106,420    1,154,789 Other                                            55,881      53,569      52,241      52,943         6,399 Total retail                                 4,776,985    4,309,972   4,288,097   4,349,312    4,317,338 Sales for resale - non-affiliates              246,545      259,376     270,678     366,085      297,643 Sales for resale - affiliates                   166,245     174,855      98,323      99,411        96,150 Total revenues from sales of electricity     5,189,775    4,744,203   4,657,098   4,814,808    4,711,131 Other revenues                                 181,033      169,304     165,362     150,986       159,487 Total                                       $5,370,808   $4,913,507  $4,822,460  $4,965,794   $4,870,618 Kilowatt-Hour Sales       (in thousands):
Residential                                 22,930,372   21,778,582  22,144,559  20,119,080   20,693,481 Commercial                                  28,014,357   26,940,572  26,954,922  26,493,255   25,628,402 Industrial                                  26,357,271   25,703,421  25,739,785  25,349,477   27,543,265 Other                                          602,202      595,742     593,202     583,007      568,906 Total retail                                77,904,202   75,018,317  75,432,468  72,544,819   74,434,054 Sales for resale - non-affiliates            5,969,983    8,835,804   8,069,375   8,110,096    6,463,723 Sales for resale - affiliates                4,782,873    5,844,196   3,962,559   3,133,485    2,435,106 Total                                       88.657.058   89.698,317  87.464,402  83.788.400   83.332.883 Average Revenue Per Kilowatt-Hour (cents):
Residential                                         7.57        7.27        7.23        7.49          7.42 Commercial                                          6.47        6.17        6.05        6.35          6.32 Industrial                                          4.45        3.94        3.90        4.36         4.19 Total retail                                        6.13        5.75        5.68        6.00          5.80 Sales for resale                                   3.84         2.96        3.07        4.14         4.43 Total sales                                        5.85         5.29        5.32        5.75          5.65 Residential Average Annual Kilowatt-Hour Use Per Customer                 12,838      12,421      12,867      11,933        12,520 Residential Average Annual Revenue Per Customer                             $972        $903        $930        $894          $929 Plant Nameplate Capacity Ratings (year-end) (megawatts)                 13,978      13,980      14,059      14,474        15,114 Maximum Peak-Hour Demand (megawatts):
Winter                                           12,208      13,153      11,873      11,977        12,014 Summer                                           15,180      14,826      14,597      14,294        14,930 Annual Load Factor (percent)                       61.5         61.0       60.4         61.7         61.6 Plant Availability (percent):
Fossil-steam                                       90.3        87.6        80.9         88.5         86.1 Nuclear                                            94.8        94.2        88.8        94.4          91.5 Source of Energy Supply (percent):
Coal                                               57.9        58.6        59.5         58.5         62.3 Nuclear                                            17.3         16.8        16.2        18.1          17.4 Hydro                                                1.5         2.1         0.9          1.1          0.7 Oil and gas                                          0.1         0.3         0.3         0.4           1.8 Purchased power -
From non-affiliates                                7.0         7.5         6.3         7.8           8.1 From affiliates                                  16.2         14.7        16.8        14.1           9.7 Total                                             100.0       100.0       100.0       100.0         100.0 57

DIRECTORS AND OFFICERS Georgia Power Company 2004 Annual Report Directors                                           Officers Juanita Powell Baranco                              Michael D. Garrett Executive Vice President                            President and Chief Executive Officer Baranco Acura                                       Georgia Power Company Robert L. Brown, Jr.                                Judy M. Anderson President and Chief Executive Officer               Senior Vice President R. L. Brown & Associates, Inc.                      Charitable Giving Ronald D. Brown                                     William C. Archer, III President and Chief Executive Officer               Executive Vice President Atlanta Life Financial Group                        External Affairs Anna R. Cablik                                      Mickey A. Brown Owner and President                                 Executive Vice President Anatek, Inc. & Anasteel & Supply Co., LLC          Customer Service Organization Michael D. Garrett                                  C. B. (Mike) Harreld (resigned effective 3/17/05)
President and Chief Executive Officer              Executive Vice President, Chief Financial Officer, Georgia Power Company                               Treasurer and Assistant Secretary David M. Ratcliffe                                 Cliff S. Thrasher (elected effective 3/17/05)
President and Chief Executive Officer              Executive Vice President, Chief Financial Officer The Southern Company                                and Treasurer D. Gary Thompson                                    Ronnie L. Bates (resigned effective 1/10/05)
Chief Executive Officer, Georgia Banking            Senior Vice President Wachovia Corporation, Retired (12/2004)             Planning, Sales and Service Richard W. Ussery                                   Richard L. Holmes Chairman of the Board                               Senior Vice President TSYS                                                Metro Region, Diversity and Corporate Relations William Jerry Vereen                                Douglas E. Jones (elected effective 1/10/05)
Chairman, President and Chief Executive Officer     Senior Vice President Riverside Manufacturing Company & Subsidiaries      Customer Service and Sales E. Jenner Wood, III                                 James H. Miller, III Chairman, President and Chief Executive Officer     Senior Vice President and SunTrust Bank, Central Group                        General Counsel Leslie R. Sibert Vice President Transmission Gene L. Ussery (elected effective 2/16/05)
Vice President Distribution Chris C. Womack Senior Vice President Fossil and Hydro Power 58

DIRECTORS AND OFFICERS Georgia Power Company 2004 Annual Report W. Craig Barrs Vice President                                        Jacki W. Lowe Community and Economic Development                    Vice President West Region Rebecca A. Blalock Vice President                                        Terri H. Lupo (elected effective 2/16/05)
Information Resources                                 Vice President South Region Walter Dukes (elected effective 2/16/05)
Vice President                                        Frank J. McCloskey East Region                                           Vice President Diversity and Corporate Relations A. Bryan Fletcher Vice President                                        James E. Sykes, Jr.
Supply Chain Management                               Vice President Northeast Region J. Kevin Fletcher Vice President                                        Jeff L. Wallace Customer Service                                      Vice President Resource Policy and Market Planning Jeff G. Franklin (elected effective 2/16/05)
Vice President                                        Thomas J. Wicker (elected effective 2/16/05)
Northwest Region                                      Vice President Central Region
: 0. Ben Harris Vice President                                        Janice G. Wolfe Land                                                  Corporate Secretary and Assistant Comptroller W. Ron Hinson Vice President, Comptroller and                        Wayne Boston Chief Accounting Officer                               Assistant Secretary and Assistant Treasurer Ed F. Holcombe Vice President Governmental and Regulatory Affairs E. Lamont Houston Vice President Corporate Services Charles H. Huling (elected effective 2/16/05)
Vice President Environmental Affairs Brian L. (Pete) Ivey (resigned effective 2/16/05)
Vice President Administrative Services Anne H. Kaiser Vice President Sales Ellen N. Lindemann Vice President Human Resources 59

CORPORATE INFORMATION Georgia Power Company 2004 Annual Report General                                             Form 10-K This annual report is submitted for general         A copy of the Form 10-K as filed with the information and is not intended for use in          Securities and Exchange Commission will connection with any sale or purchase of, or         be provided upon written request to the any solicitation of offers to buy or sell           office of the Corporate Secretary. For securities.                                         additional information, contact the office of the Corporate Secretary at (404) 506-7450.
Profile The Company produces and delivers                   Georgia Power Company electricity as an integrated utility to retail      241 Ralph McGill Boulevard, N.E.
customers within the State of Georgia and to        Atlanta, GA 30308-3374 wholesale customers in the Southeast. The           (404) 506-6526 Company sells electricity to almost 2.1             www.georgiapower.com million customers within its service area of approximately 57,000 square miles. In 2004,         Auditors retail energy sales accounted for 88 percent of     Deloitte & Touche LLP the Company's total sales of 88.7 billion           Suite 1500 kilowatt-hours.                                     191 Peachtree Street, N.E.
Atlanta, GA 30303 The Company is a wholly owned subsidiary of The Southern Company, which is Legal Counsel the parent company of five retail operating         Troutman Sanders LLP companies and a wholesale generation                600 Peachtree Street, N.E.
subsidiary, as well as other direct and indirect    Suite 5200 subsidiaries. There is no established public        Atlanta, GA 30308 trading market for the Company's common stock.
Trustee, Registrar and Interest Paying Agent All series of Senior Notes and Trust Preferred Securities JPMorgan Chase Bank, N.A.
Institutional Trust Services 4 New York Plaza, 1 5 th Floor New York, NY 10004 Registrar, Transfer Agent and Dividend Paying Agent Preferred Stock Southern Company Services, Inc.
Stockholder Services P.O. Box 54250 Atlanta, GA 30308-0250 (800) 554-7626 60}}