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

Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.21)

ML052100358
Person / Time
Site:	Hatch, Vogtle
Issue date:	07/27/2005
From:	Aubuchon R Georgia Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-05-1222
Download: ML052100358 (70)

Text

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

NOTES (continued)

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

NOTES (continued)

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

NOTES (continued)

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

NOTES (continued)

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

NOTES (continued)

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