NL-04-0978, Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.21)

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

ML042160126
Person / Time
Site:	Hatch, Vogtle
Issue date:	07/30/2004
From:	Aubuchon R Georgia Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-04-0978
Download: ML042160126 (62)

Text

Bin 10120 241 Ralph McGill Boulevard NE Atlanta, Georgia 30308-3374 Tel 404.506.6526 July 30, 2004 GEORGIAAM POWER A SOUTHERN COMPANY Docket Nos.: 50-321 50-424 NL-04-0978 50-366 50-425 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin 1. Hatch Nuclear Plant Vogtle Electric Generating Plant Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.21)

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):

I. An Annual Report containing certified financial statements for calendar year 2003.

2. A set of quarterly financial statements for the period ending June 30, 2004.

3. A one year projected Cash Flows Statement for period January 1, 2005, through December 31, 2005.

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 0AOUA

U. S. Nuclear Regulatory Commission NL-04-0978 Page 2 cc: Southern Nuclear Operating Company Mr. J. B. Beasley, Jr., Executive Vice President Mr. H. L. Sumner, Jr., Vice President, Plant Hatch Mr. J. T. Gasser, Vice President, Plant Vogtle Mr. G. R. Frederick, General Manager - Plant Hatch Mr. W. F. Kitchens, General Manager - Plant Vogtle RType: Hatch=CHAO2.004; Vogtle=CVC7000 U. S. Nuclear Remulatory 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. J. Zeiler, 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, 2004 2003 2004 2003 OPERATING REVENUES:

Retail sales $1,199,220 $1,041,604 $2,237,015 $2,007,311 Sales for resale-Non-affiliates $62,191 59,452 $127,647 $133,438 Affiliates $48,357 46,365 $102,499 $93,851 Other revenues S43,394 42,672 $85,390 $81,931 Total operating revenues 1,353,162 1,190,093 2,552,551 2,316,531 OPERATING EXPENSES:

Operation-Fuel 324,220 271,428 609,434 513,931 Purchased power-Non-affiliates 98,638 62,052 161,327 134,088 Affiliates 138,073 121,605 273,215 235,448 Other 220,799 199,487 419,192 385,477 Maintenance 124,675 107,628 233,143 218,572 Depreciation and amortization 68,542 86,003 136,279 171,745 Taxes other than Income taxes 56,488 49,290 112,920 102,465 Total operating expenses 1,031,435 897,493 1,945,510 1,761,726 OPERATING INCOME 321,727 292,600 607,041 554,805 OTHER INCOME (EXPENSE):

Allowance for equity funds used during construction 4,700 846 8,047 3,802 Interest Income 1,768 14,970 4,120 15,085 Interest expense, net of amounts capitalized (48,293) (47,925) (93,943) (92,288)

Interest expense to affiliate trusts (15,300) (15,300)

Distributions on preferred securities of subsidiaries (14,919) (15,839) (29,838)

Other Income (expense), net (5,123) 9,353 (9,518) 12,265 Total other Income and (expense) (62,248) (37,675) (122,433) (90,974)

EARNINGS BEFORE INCOME TAXES 259,479 254,925 484,608 463,831 Income taxes 103,597 96,231 184,717 171,699 NET INCOME 155,882 158,694 299,891 292,132 DIVIDENDS ON PREFERRED STOCK 167 167 335 335 NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $155,715 5158,527 $299,556 S291,797 Note: Certainprior 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, 2004 2003 ASSETS CURRENT ASSETS:

Cash and cash equivalents $20,258 $10,799 Receivables -

Customer accounts receivable 300,311 279,288 Unbilled revenues 167,852 132,307 Under recovered regulatory clause revenue 254,428 125,052 Other accounts and notes receivable 77,475 74,943 Affiliated companies 30,935 38,691 Accumulated provision for uncollectible accounts (6,025) (5,825)

Fossil fuel stock, at average cost 143,846 142,705 Materials and supplies, at average cost 273,720 271,364 Other 76,788 62,396 Total Current Assets 1,339,588 1,131,720 PROPERTY, PLANT AND EQUIPMENT:

In service 18,472,477 17,894,675 Less accumulated provision for depreciation 7,068,465 7,183,011 11,404,012 10,711,664 Nuclear fuel, at amortized cost 116,191 112,508 Construction work in progress 639,952 403,677 Total Property, Plant and Equipment 12.160.155 11.227.849 OTHER PROPERTY AND INVESTMENTS:

Equity investments in unconsolidated subsidiaries 68,702 38,095 Nuclear decommissioning trusts 437,441 387,601 Other 64,891 29,480 Total Other Property and Investments 571,034 455,176 DEFERRED CHARGES AND OTHER ASSETS:

Deferred charges related to income taxes 504,470 516,618 Prepaid pension costs 426,899 370,464 Unamortized debt issuance expense 74,852 75,344 Unamortized loss on reacquired debt 182,286 177,496 Other 160,597 163,121 Total Deferred Charges and Other Assets 1,349,104 1,303,043 TOTAL ASSETS $15,419,881 $14,117,788

GEORGIA POWER COMPANY CONDENSED BALANCE SHEETS (UNAUDITED)

(Stated in Thousands of Dollars)

At June 30, At June 30, 2004 2003 LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES:

Securities due within one year $302,401 $2,215 Notes payable 372,027 340,044 Accounts payable -

Affiliated companies 154,541 115,804 Other 236,621 259,774 Customer deposits 109,204 99,418 Taxes accrued Income taxes 172,250 80,085 Other 104,271 91,031 Interest accrued 71,861 65,900 Vacation pay accrued 42,749 40,844 Other 195,185 126,845 Total Current Liabilities 1,761,110 1,221,960 LONG-TERM DEBT 3,611,093 3,663,476 LONG-TERM DEBT PAYABLE TO AFFILIATED TRUSTS 969,073 MANDATORILY REDEEMABLE PREFERRED SECURITIES 940,000 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred income taxes 2,358,073 2,238,686 Deferred credits related to income taxes 178,986 200,822 Accumulated deferred investment tax credits 306,262 318,750 Employee benefits provisions 306,543 247,634 Asset retirement obligations 490,164 484,323 Other 630,577 336,897 Total Deferred Credits and Other Liabilities 4,270,605 3,827,112 PREFERRED STOCK 14,569 14,569 COMMON STOCKHOLDER'S EQUITY:

Common stock 344,250 344,250 Paid-in capital 2,437,069 2,165,789 Premium on preferred stock 40 40 Retained earnings 2,027,103 1,954,415 Accumulated other comprehensive income (15,031) (13,823)

Total Common Stockholder's Equity 4,793,431 4,450,671 TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $15,419,881 $14,117,788

GEORGIA POWER COMPANY CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Stated in Thousands of Dollars)

FOR THE SIX MONTHS ENDED JUNE 2004 2003 OPERATING ACTIVITIES:

Net income 5299,891 $292,132 Adjustments to reconcile net income to net cash provided by operating activities -

Depreciation and amortization 177,928 220,464 Deferred Income taxes and investment tax credits, net 127,958 93,581 Pension, postretirement, and other employee benefits (10,980) 7,216 Other, net (12,467) 8,167 Changes In certain current assets and liabilities -

Receivables, net (146,026) 33,395 Fossil fuel stock (6,309) (22,658)

Materials and supplies (2,680) (8,000)

Other current assets 29,779 31,641 Accounts payable (4,477) (72,695)

Taxes accrued (78,952) 16,600 Other current liabilities 25,648 (66,112)

NET CASH PROVIDED FROM OPERATING ACTIVITIES 399,313 508,192 INVESTING ACTIVITIES:

Gross property additions (672,424) (370,727)

Cost of removal net of salvage (14,236) (10,786)

Other (14,024) (61,789)

NET CASH USED FOR INVESTING ACTIVITIES (700,684) (443,302)

FINANCING ACTIVITIES:

Increase (decrease) in notes payable, net 234,749 (17,633)

Proceeds -

Senior notes 350,000 700,000 Shares subject to mandatory redemption 200,000 Capital contributions from parent company 223,000 9,748 Redemptions -

First mortgage bonds Shares subject to mandatory redemption (200,000)

Senior notes (200,000) (465,000)

Payment of preferred stock dividends (209) (393)

Payment of common stock dividends (282,750) (282,900)

Other (11,860) (14,786)

NET CASH PROVIDED FROM FINANCING ACTIVITIES 312,930 (70,964)

NET CHANGE IN CASH AND CASH EQUIVALENTS 11,559 (6,074)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 8,699 16,872 CASH AND CASH EQUIVALENTS AT END OF PERIOD S20,258 S1 0,798 Note: Certainprior period amounts have been reclassified to conform with current period presentation.

GEORGIA POWER COMPANY PROJECTED STATEMENT OF CASH FLOWS 2005 FORECAST (Stated in Thousands of Dollars) 2005 FORECAST OPERATING ACTIVITIES Net income before preferred dividends $468,838 Principal noncash items-Depreciation and amortization 562,765 Deferred income taxes, net 40,381 Allowance for equity funds used during construction (2,091)

Pension, postretirement and other employee benefits (27,482)

Other, net 45,549 Change In current assets & liabilities-Receivables 34,406 Inventories 4,835 Accounts payable (5,574)

Other current assets and liabilities 65,572 NET CASH PROVIDED FROM OPERATING ACTIVITIES 1,187,199 INVESTING ACTIVITIES Gross property additions (812,439)

Cost of removal, net of salvage (26,946)

Allowance for equity funds used during construction 2,091 Other property and Investments (6,347)

NET CASH USED FOR INVESTING ACTIVITIES (843,641)

FINANCING ACTIVITIES Increase in notes payable, net 68,320 Proceeds -

Senior notes 400,000 Trust preferred securities 75,000 Capital contributions from parent company 105,991 Redemptions -

Senior notes (450,000)

Capitalized leases (2,497)

Payment of preferred stock dividends (672)

Payment of common stock dividends (530,200)

Other (9,500)

NET CASH USED FOR FINANCING ACTIVITIES (343,558)

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

2 003 Annual Report GEORGIA A POWER A SOUTHERN COMPANY

CONTENTS Georgia Power Company 2003 Annual Report 1

SUMMARY

2 LETTER TO INVESTORS 4 MANAGEMENT'S REPORT 5 INDEPENDENT AUDITORS' REPORT 6 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION 23 FINANCIAL STATEMENTS 29 NOTES TO FINANCIAL STATEMENTS 50 SELECTED FINANCIAL AND OPERATING DATA 52 DIRECTORS AND OFFICERS 54 CORPORATE INFORMATION

SUMMARY

Percent 2003 2002 Change Financial Highlights (in millions):

Operating revenues S4,914 $4,822 1.9 Operating expenses $3,690 $3,618 2.0 Net income after dividends on preferred stock $631 5618 2.1 Operating Data:

Kilowatt-hour sales (inmillions):

Retail 75,018 75,432 (0.5)

Sales for resale - non-affiliates 8,836 8,069 9.5 Sales for resale - affiliates 5,844 3,963 47.5 Total 89,698 87,464 2.6 Customers served at year-end (in thousands) 2,038 1,997 2.1 Peak-hour demand (in megawatts) 14,826 14,597 1.6 Capitalization Ratios (percent):

Common stock equity 49.0 52.2 Preferred stock 0.2 0.2 Mandatorily redeemable preferred securities 10.2 11.1 Long-term debt 40.6 36.5 Return on Average Common Equity (percent) 14.05 13.99 Ratio of Earnings to Fixed Charges (times) 5.01 5.07 I

LETTER TO INVESTORS Georgia Power Company 2003 Annual Report Georgia Power's strong financial and operational performance in 2003 resulted in an outstanding year for the company. Reliability at our plants was at an all-time high. We led the industry in customer satisfaction. And we continued to expand our transmission and distribution infrastructure to meet the energy demands of our growing customer base.

Georgia Power's earnings for 2003 totaled $631 million, a $13 million, or 2.1 percent increase, from 2002. We earned a 14.05 percent total company return on average common equity during 2003. Georgia Power had a net plant in service investment of $11.3 billion at the end of the year, with total assets of $14.8 billion. Operating revenues for 2003 were $4.9 billion.

The company's solid financial performance occurred despite one of the mildest summers on record. The mercury reached 90 degrees in Atlanta on only seven days in 2003, reducing electricity sales to retail customers. However, continued customer growth, despite the weak economy, partially offset the weather's impact on earnings.

We're fortunate to live in a state that's attracting new people and businesses. Because of this growth, we increased our customer base last year by 41,280 to more than 2 million.

Our total sales of electricity climbed 2.6 percent in 2003 as we maintained an excellent reliability record. In fact, Georgia Power plants achieved a stellar peak season equivalent forced outage rate of 1.77 percent, surpassing our peak goal of 2.90 percent.

At the same time, we're being recognized nationally for how satisfied our customers are with the service we provide. For instance, for the fifth consecutive year, Southern Company, including Georgia Power, ranks No. 1 for overall customer satisfaction for electric service to midsize businesses in the South, according to a J. D. Power and Associates survey.

As testament to our reputation, several hundred Georgia Power employees headed to the Washington, D.C., area and North Carolina last fall to help restore widespread power outages in the wake of Hurricane Isabel. The storm left more than 4 million customers of utilities in those areas without power. Our employees continue to receive accolades for their professionalism and productivity.

Georgia Power prospered last year because we succeeded at managing the fundamentals of our business - generating and supplying power to our customers - and we're offering our customers more and more services to meet their needs.

For example, more than 100,000 customers have signed up for e-Bill, a service launched in 2001 that offers customers the ability to receive and pay their utility bills online through our Internet site. When customers requested more options for how they purchase energy, we introduced FlatBill statewide in 2002. The fixed-bill pricing plan was recognized last year with a 2003 Platts Global Energy Award for "Marketing Campaign of the Year."

2

As we run our business and take care of our customers, we're making great strides in minimizing our impact on the environment.

Last year, we completed a four-year, $800 million effort to retrofit power plants with various environmental control systems. The work included installing selective catalytic reduction systems on seven units to dramatically reduce emissions of nitrogen oxides (NOx), which contribute to the formation of ozone. The new controls will reduce NOx emissions by about 50 percent annually from 1990 levels, which will help the state comply with federal ozone standards.

The company's former president and CEO, David Ratcliffe, was named Diversity CEO of the Year last year as part of the Georgia Minority Business Awards. Georgia Power also was named Corporation of the Year, and David was named Executive of the Year at the Georgia Minority Supplier Development Council's Business Opportunity Expo.

Supplier diversity is a key goal for our company. In fact, we're committed to becoming a role model for supplier diversity, so it's gratifying to receive this recognition. Last year, we spent

$133 million, or 10.5 percent of our total procurement dollars, excluding fuel, with minority- and female-owned businesses. We surpassed our goal of 9 percent. Our goal for 2004 is 11.25 percent.

As the company's new CEO succeeding Mr. Ratcliffe, I realize I have big shoes to fill, but I look forward to the challenge. Growth in the area and the increasing energy needs of our customers have made it important for us to keep pace by expanding our electricity infrastructure and the services we offer our customers.

In 2004, we'll take the steps necessary to prepare for the future and ensure that our customers continue to receive reliable, cost-effective electricity for many years to come.

Sincerely, Michael D. Garrett March 19, 2004 3

MANAGEMENT'S REPORT Georgia Power Company 2003 Annual Report The management of Georgia Power Company has Southern Company's audit committee of its board of prepared -- and is responsible for - the financial directors, composed of four independent directors, statements and related information included in this report. provides a broad overview of management's financial These statements were prepared in accordance with reporting and control functions. Additionally, the accounting principles generally accepted in the United Controls and Compliance Committee of the Company's States and necessarily include amounts that are based on board of directors, composed of a minimum of three the best estimates and judgments of management. outside directors, meets periodically with management, Financial information throughout this annual report is the internal auditors, and the independent public consistent with the financial statements. accountants to discuss auditing, internal controls, and compliance matters. The internal auditors and The Company maintains a system of internal independent public accountants have access to the accounting controls to provide reasonable assurance that members of these committees at any time.

assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Management believes that its policies and procedures Limitations exist in any system of internal controls, provide reasonable assurance that the Company's however, based upon recognition that the cost of the operations are conducted with a high standard of business system should not exceed its benefits. The Company ethics.

believes its system of internal accounting controls maintains an appropriate cost/benefit relationship. In management's opinion, the financial statements present fairly, in all material respects, the financial The Company's internal accounting controls are position, results of operations and cash flows of Georgia evaluated on an ongoing basis by the Company's internal Power Company in conformity with accounting principles audit staff. The Company's independent public generally accepted in the United States.

accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.

Cip C A74 David M. Ratcliffe C. B. Harreld Chief Executive Officer t/ Executive Vice President, Treasurer, and Chief Financial Officer March 1, 2004 Michael D. Garrett President 4

INDEPENDENT AUDITORS' REPORT Georgia Power Company:

We have audited the accompanying balance sheets and misstatement. An audit includes examining, on a test statements of capitalization of Georgia Power Company (a basis, evidence supporting the amounts and disclosures in wholly owned subsidiary of Southern Company) as of the financial statements. An audit also includes assessing December 31, 2003 and 2002, and the related statements the accounting principles used and significant estimates of income, comprehensive income, common stockholder's made by management, as well as evaluating the overall equity, and cash flows of the years then ended. These financial statement presentation. We believe that our financial statements are the responsibility of Georgia audits provide a reasonable basis for our opinion.

Power Company's management. Our responsibility is to express an opinion on these financial statements based on In our opinion, the financial statements (pages 23 to our audits. The financial statements of Georgia Power 49) present fairly, in all material respects, the financial Company for the year ended December 31, 2001 were position of Georgia Power Company at December 31, audited by other auditors who have ceased operations. 2003 and 2002, and the results of its operations and its Those auditors expressed an unqualified opinion on those cash flows for the years then ended in conformity with financial statements and included an explanatory accounting principles generally accepted in the United paragraph that described a change in the method of States of America.

accounting for derivative instruments and hedging activities in their report dated February 13, 2002. As discussed in Note I to the financial statements, in 2003 Georgia Power Company changed its method of We conducted our audits in accordance with auditing accounting for asset retirement obligations.

standards generally accepted in the United States of America. Those standards require that we plan and -4A"- t LL perform the audit to obtain reasonable assurance about Atlanta, Georgia whether the financial statements are free of material March 1, 2004 TIlE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THIE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTIIUR ANDERSEN LLP.

To Georgia Power Company:

We have audited the accompanying balance sheets and estimates made by management, as well as evaluating statements of capitalization of Georgia Power Company the overall financial statement presentation. We believe (a Georgia corporation and a wholly owned subsidiary of that our audits provide a reasonable basis for our Southern Company) as of December 31, 2001 and 2000, opinion.

and the related statements of income, comprehensive In our opinion, the financial statements (pages 16-income, common stockholder's equity, and cash flows 36) referred to above present fairly, in all material for each of the three years in the period ended December respects, the financial position of Georgia Power 31, 2001. These financial statements are the Company as of December 31, 2001 and 2000, and the responsibility of the Company's management. Our results of its operations and its cash flows for each of the responsibility is to express an opinion on these financial three years in the period ended December 31, 2001, in statements based on our audits. conformity with accounting principles generally accepted in the United States.

We conducted our audits in accordance with auditing standards generally accepted in the United As explained in Note 1 to the financial statements, States. Those standards require that we plan and effective January 1, 2001, Georgia Power Company perform the audit to obtain reasonable assurance about changed its method of accounting for derivative whether the financial statements are free of material instruments and hedging activities.

misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes Atlanta, Georgia assessing the accounting principles used and significant February 13, 2002 5

MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 2003 Annual Report OVERVIEW OF EARNINGS AND BUSINESS price of electricity, the price elasticity of demand, and ACTIVITIES the rate of economic growth in the service area.

Earnings RESULTS OF OPERATIONS Georgia Power Company's 2003 earnings totaled A condensed income statement for the Company is as

$631 million, representing a $13 million (2.1 percent) follows:

increase over 2002. Operating income increased in 2003 despite lower base retail revenues resulting from the extremely mild summer weather. Higher wholesale Increase (Decrease) revenues and lower non-fuel operating expenses Amount From Prior Year contributed to the increase. The Company's 2002 2003 2003 2002 2001 earnings totaled $618 million, representing an $8 million (in millions)

(1.2 percent) increase over 2001. Operating income Operating revenues $4,914 $ 92 $(144) $ 95 declined slightly in 2002. Lower retail and wholesale Fuel 1,104 101 64 (79) revenues, higher other operating and maintenance Purchased power 776 92 (87) 175 expenses and increased purchased power capacity Other operation expenses were significantly offset by lower depreciation and maintenance 1,247 (78) 85 41 and amortization expense as a result of a Georgia Public Depreciation and Service Commission (GPSC) retail rate order effective amortization 350 (54) (197) (19)

January 2002. The increase in net income for 2002 Taxes other than resulted from lower financing costs and a lower effective income taxes 213 11 (1) (1) tax rate due to the realization of certain state tax credits.

The Company's 2001 earnings totaled $610 million, Total operating representing a $51 million (9.1 percent) increase over expenses 3,690 72 (136) 117 2000. Operating income was lower in 2001 compared to Operating income 1,224 20 (8) (22) 2000 due to the impact of mild weather on retail Other income and revenues; however, overall net income improved due to (expense) (227) 2 9 76 lower financing costs and non-operating expenses and a Less-lower effective tax rate resulting from various factors Income taxes 366 9 (7) 3 including property donations and positive resolution of Netincome $ 631 $ 13 $ 8 $ 51 outstanding tax issues.

Business Activities The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast.

Several factors affect the opportunities, challenges and risk of the Company's primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly strict environmental standards. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the 6

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report Revenues existing under-recovered deferred fuel costs. See Note 3 to the financial statements under "Fuel Cost Recovery" Operating revenues in 2003, 2002, and 2001 and the for further information regarding this order.

percent of change from the prior year are as follows:

Wholesale revenues from sales to non-affiliated Amount utilities were:

2003 2002 2001 2003 2002 2001 (in niillions)

(in millions)

Retail - prior year $4,288 $4,349 $4,317 Unit power sales -

Change in -

Capacity $ 34 $ 34 $ 26 Base rates (118)

Sales growth and other 30 2 90 Energy 31 34 35 Weather (66) 82 (107) Other power sales --

Fuel cost recovery Capacity 38 41 72 and other 58 (27) 49 -

Energy 157 162 233 Retail - current year 4,310 4,288 4,349 Total $260 $271 $366 Sales for resale -

Non-affiliates 260 271 366 Revenues from unit power contracts decreased Affiliates 175 98 100 slightly in 2003 due to decreased energy sales.

Total sales for resale 435 369 466 Approximately 103 megawatts of capacity is scheduled Other operating revenues 169 165 151 to be 'sold annually through 2010. Revenues from other Total operating revenues $4,914 $4,822 $4,966 non-affiliated sales decreased $8 million (3.9 percent) in Percent change 1.9% (2.9)% 2.0% 2003, decreased $102 million (33.4 percent) in 2002 and increased $62 million in 2001 primarily due to Retail base revenues of $3.0 billion in 2003 fluctuations in off-system sale transactions that were decreased by $36 million (1.2 percent) from 2002 generally offset by corresponding purchase transactions.

primarily due to extremely mild summer temperatures in These transactions had no significant effect on income.

2003 and the sluggish economy. Residential kilowatt- In 2002, revenues also decreased $37 million as a result hour (KWH) sales decreased by 1.7 percent. Retail base of transferring Plant Dahlberg to Southern Power revenues of $3.1 billion in 2002 decreased by $34 Company (Southern Power) in July 2001.

million (1.1 percent) from 2001 primarily due to a base rate reduction effective January 2002 under the GPSC Revenues from sales to affiliated companies within retail rate order and generally lower prices to large the Southern Company electric system, as well as business customers. This decrease was partially offset purchases of energy, will vary from year to year by a 10.1 percent increase in residential KWH sales due depending on demand and the availability and cost of to warmer weather. Retail base revenues of $3.1 billion generating resources at each company. In 2003, energy in 2001 decreased $17 million (0.5 percent) from 2000, sales to affiliates increased 47.5 percent due to the primarily due to a 2.5 percent decrease in retail KWH combination of increased demand by Southern Power to sales from the prior year. Milder-than-normal weather meet contractual obligations and the availability of and a slowdown in the economy contributed to the power due to mnilder-than-normal weather in the decline in such sales. Company's service territory. These transactions do not have a significant impact on earnings since this energy is Electric rates include provisions to adjust billings for generally sold at marginal cost.

fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under Other operating revenues increased $4 million (2.4 these fuel cost recovery provisions, fuel revenues percent) in 2003 primarily due to an increase in the open generally equal fuel expenses - including the fuel access transmission tariff rate, which increased revenues component of purchased energy - and do not affect net $7 million, and higher revenues from' increased customer income. As of December 31, 2003, the Company had demand for outdoor lighting services of $4 million,

$151 million in under-recovered fuel costs. On August partially offset by lower revenue from the rental of 19, 2003, the GPSC issued an order allowing the electric property of $4 million. See Note 3 to the Company to increase customer fuel rates to recover financial statements under "Open Access Transmission 7

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report Tariff" for further information regarding the increase in Expenses the open access transmission tariff rate. Other operating revenues in 2002 increased $14 million (9.5 percent) Fuel costs constitute the single largest expense for the primarily due to the collection of new late payment fees Company. The mix of fuel sources for generation of approved under the retail rate order effective January electricity is determined primarily by system load, the 2002 of $7 million and higher revenues from increased unit cost of fuel consumed, and the availability of hydro customer demand for outdoor lighting services of $5 and nuclear generating units. The amount and sources of million and the transmission of electricity of $3 million. generation and the average cost of fuel per net kilowatt-Other operating revenues in 2001 decreased $9 million hour generated were as follows:

(5.3 percent) primarily due to lower gains on the sale of generating plant emission allowances, partially offset by 2003 2002 2001 increased revenues from the transmission of electricity Total generation and from the rental of electric equipment and property. (billions of KWHI) 73.1 70.4 68.9 Sources of generation Energy Sales (percent) -

Coal 75.4 77.4 74.9 KWH sales for 2003 and the percent change by year Nuclear 21.6 21.1 23.2 were as follows: Hydro 2.7 1.2 1.4 Oil and gas 0.3 0.3 0.5 KWH Percent Change Average cost of fuel per net 2003 2003 2002 2001 KWH generated (in billions) (cents) -- 1.46 1.42 1.38 Residential 21.8 (1.7)% 10.1% (2.8)% Average cost of purchased Commercial 26.9 (0.1) 1.7 3.4 power per net KWH Industrial 25.7 (0.1) 1.5 (8.0) (cents) -- 4.03 3.29 3.79 Other 0.6 0.4 1.7 2.5 Total retail 75.0 (0.5) 4.0 (2.5) Fuel expense increased 10.1 percent in 2003 due to Sales for resale - an increase in generation of 3.9 percent because of Non-affiliates 8.9 9.5 (0.5) 25.5 higher wholesale energy demands and a 2.8 percent Affiliates 5.8 47.5 26.5 28.7 higher average cost of fuel due to the higher prices of Total sales for coal and natural gas in 2003. Fuel expense increased 6.8 resale 14.7 22.0 7.0 26.3 percent in 2002 due to a 2.2 percent increase in Total sales 89.7 2.6 4.4 0.5 generation because of higher energy demands and a 2.9 percent higher average cost of fuel due to the higher cost Residential KWH sales decreased 1.7 percent in of coal. In 2001, fuel expense decreased 7.7 percent due 2003 due to the effect of the milder summer weather to a decrease in generation because of lower energy despite the 2 percent increase in residential customers. demands and a slightly lower average cost of fuel.

Commercial KWH sales declined slightly due to the milder summer weather, while industrial KWH sales Purchased power expense increased $91 million declined slightly due to the sluggish economy. (13.3 percent) in 2003 primarily due to $75 million of Residential KNWH sales increased 10.1 percent in 2002 additional capacity expense associated with new due to the effect of the warmer weather. Commercial purchased power contracts that went into effect in 2003 and industrial KWH sales increased 1.7 percent and 1.5 and 2002. Purchased power expense decreased $87 percent, respectively, due to corresponding increases of million (11.2 percent) in 2002 and increased $175 2.6 percent and 2.4 percent, respectively, in customers. million (29.4 percent) in 2001 primarily due to Residential KWH sales decreased 2.8 percent in 2001 fluctuations in off-system energy purchases used to meet due to milder-than-normal weather. Commercial KWH off-system sales commitments. The 2002 decrease in sales increased 3.4 percent due to an increase in energy purchases was partially offset by a $43 million customers, while industrial KWH sales decreased 8.0 increase in capacity expense associated with new percent due to an economic slowdown. Retail sales purchased power contracts.

growth assuming normal weather is expected to be 1.6 percent on average from 2004 to 2013.

8

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report In 2003, other operation and maintenance expenses in 2001 during the construction phase of these new decreased $78 million (5.9 percent) due to the timing of projects. See Note 7 to the financial statements under generating plant maintenance of $46 million and "Construction Program" for additional information transmission and distribution maintenance of $8 million regarding the construction and subsequent transfer of and lower severance costs of $8 million. In 2002, other these generation assets. Distributions on mandatorily operation and maintenance expenses increased $85 redeemable preferred securities decreased in 2003 due to million (6.8 percent) due to the timing of generating the redemption of securities in the second half of 2002 plant maintenance of $44 million and transmission and increased in 2002 due to the issuance of additional maintenance of $17 million, and increased property securities while remaining unchanged in 2001.

insurance expense of $5 million. In 2001, other operation and maintenance expenses increased $41 Effects of Inflation million (3.4 percent) due to additional severance costs, increased scheduled generating plant maintenance, and The Company is subject to rate regulation that is based higher uncollectible account expense. on the recovery of historical costs. In addition, the income tax laws are also based on historical costs.

Depreciation and amortization decreased $54 million Therefore, inflation creates an economic loss because the in 2003 primarily as a result of lower regulatory charges Company is recovering its costs of investments in dollars related to the inclusion of new certified purchased power that have less purchasing power. While the inflation rate costs in retail rates on a levelized basis as ordered by the has been relatively low in recent years, it continues to GPSC. Depreciation and amortization decreased $197 have an adverse effect on the Company because of the million in 2002 primarily as a result of discontinuing large investment in utility plant with long economic accelerated depreciation, beginning amortization of the lives. Conventional accounting for historical cost does regulatory liability for accelerated cost recovery, and not recognize this economic loss nor the partially lowering the composite depreciation rates in January offsetting gain that arises through financing facilities 2002 all in accordance with the retail rate order. with fixed-money obligations such as long-term debt and Depreciation and amortization decreased $19 million in preferred securities. Any recognition of inflation by 2001 primarily due to lower accelerated amortization regulatory authorities is reflected in the rate of return under the third year of a prior GPSC retail rate order. allowed in the Company's approved electric rates.

See Note 3 to the financial statements under "Retail Rate Orders" for additional information. Future Earnings Potential Taxes other than income taxes increased $11 million General (5.4 percent) in 2003 due mainly to a favorable true-up of state property tax valuations in 2002. Taxes other The results of operations for the past three years are not than income taxes remained relatively constant in 2002. necessarily indicative of future earnings. The level of future earnings depends on numerous factors including Interest income increased $12 million in 2003 when the Company's ability to maintain a stable regulatory compared to the prior year due to interest on a favorable environment, to achieve energy sales growth while income tax settlement of $14.5 million. Interest income containing costs, and to recover costs related to growing remained relatively constant in 2002. demand and increasingly strict environmental standards.

Interest expense increased in 2003 primarily related Growth in energy sales is subject to a number of to an increase in senior notes outstanding that was factors which include weather, competition, new energy partially offset by a reduction in short-term debt contracts with neighboring utilities, energy conservation outstanding. Interest expense decreased in 2002 and practiced by customers, the price of electricity, the price 2001 primarily due to lower interest rates that offset new elasticity of demand, and the rate of economic growth in financing costs. The Company refinanced or retired the service area.

$665 million, $929 million, and $775 million of securities in 2003, 2002, and 2001, respectively. Interest Industry Restructuring capitalized decreased in 2003 and 2002 due to the transfer of three new generation projects to Southern The Company operates as a vertically integrated utility Power in 2002 and 2001. Interest capitalized increased providing electricity to retail customers within its 9

MANAGENIENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report traditional service area located in the State of Georgia competition. Conversely, future regulatory changes and to wholesale customers in the Southeast. Prices for could adversely affect the Company's growth, and if the electricity provided by the Company to retail customers Company does not remain a low-cost producer and are set by the GPSC under cost-based regulatory provide quality service, then energy sales growth could principles. be limited, and this could significantly erode earnings.

The electric utility industry in the United States is EnvironmentalMatters continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of New Source Review Actions change was the Energy Policy Act of 1992 (Energy Act).

The Energy Act allowed independent power producers to In November 1999, the Environmental Protection access a utility's transmission network and sell Agency (EPA) brought a civil action against the electricity to other utilities. Company alleging the Company had violated the New Source Review (NSR) provisions of the Clean Air Act Although the Energy Act does not provide for retail with respect to coal-fired generating facilities at the customer access, it was a major catalyst for restructuring Company's Bowen and Scherer plants. The civil action and consolidations that took place within the utility requests penalties and injunctive relief, including an industry. Numerous federal and state initiatives that order requiring the installation of the best available promote wholesale and retail competition are in varying control technology at the affected units. The action stages. Among other things, these initiatives allow retail against the Company has been stayed since the spring of customers in some states to choose their electricity 2001 during the appeal of a very similar NSR action provider. Some states have approved initiatives that against the Tennessee Valley Authority before the U.S.

result in a separation of the ownership and/or operation Court of Appeals for the Eleventh Circuit. The Eleventh of generating facilities from the ownership and/or Circuit appeal was decided on September 16, 2003, and, operation of transmission and distribution facilities. on February 13, 2004, the EPA petitioned the U.S.

While various restructuring and competition initiatives Supreme Court to review the Eleventh Circuit's have been discussed in Georgia, none have been enacted. decision. At this time, no party to the Company's Enactment could require numerous issues to be resolved, action, which was administratively closed two years ago, including significant ones relating to recovery of any has asked the court to reopen that case. See Note 3 to stranded investments, full cost recovery of energy the financial statements under "New Source Review produced, and other issues related to the energy crisis Actions" for additional information.

that occurred in California, as well as the August 2003 power outage in the Northeast. The Company does In December 2002 and October 2003, the EPA compete with other electric suppliers within the state. In issued final revisions to its NSR regulations under the Georgia, most new retail customers with at least 900 Clean Air Act. The December 2002 revisions included kilowatts of connected load may choose their electricity changes to the regulatory exclusions and the methods of supplier. calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Since 2001, merchant energy companies and Maintenance Repair and Replacement exclusion. A traditional electric utilities with significant energy coalition of states and environmental organizations filed marketing and trading activities have come under severe petitions for review of these revisions with the U.S.

financial pressures. Many of these companies have Court of Appeals for the District of Columbia Circuit.

completely exited or drastically reduced all energy On December 24, 2003, the Court of Appeals granted a marketing and trading activities and sold foreign and stay of the October 2003 revisions pending its review of domestic electric infrastructure assets. The Company the rules, and ordered that its review would be conducted has not experienced any material financial impact on an expedited basis. In January 2004, the Bush regarding its limited energy trading operations through Administration announced that it would continue to Southern Company Services (SCS). enforce the existing rules until the courts resolve legal challenges to the EPA's revised NSR regulations. In any Continuing to be a low-cost producer could provide event, the final regulations must be adopted by the State opportunities to increase the size and profitability in of Georgia in order to apply to the Company's facilities.

markets that evolve with changing regulation and 10

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report The effect of these final regulations and the related legal Requirements and Contractual Obligations." There is no challenges cannot be determined at this time. assurance, however, that all such costs will, in fact, be recovered.

The Company believes that it complied with applicable laws and the EPA's regulations and Compliance with the federal Clean Air Act and interpretations in effect at the time the work in question resulting regulations has been, and will continue to be, a took place. The Clean Air Act authorizes civil penalties significant focus for the Company. The Title IV acid of up to $27,500 per day, per violation at each rain provisions of the Clean Air Act, for example, generating unit. Prior to January 30, 1997, the penalty required significant reductions in sulfur dioxide and was $25,000 per day. An adverse outcome in this matter nitrogen oxide emissions. Title IV compliance was could require substantial capital expenditures and effective in 2000 and associated construction additional operation and maintenance expenses that expenditures totaled approximately $206 million. Some cannot be determined at this time and could possibly of these expenditures also assisted the Company in require payment of substantial penalties. This could complying with nitrogen oxide emission reduction affect future results of operations, cash flows, and requirements under Title I of the Clean Air Act, which possibly financial condition if such costs are not were designed to address one-hour ozone nonattainment recovered through regulated rates. problems in Atlanta, Georgia. The State of Georgia adopted regulations that required additional nitrogen Plant Wansley EnvironmentalLitigation oxide emission reductions from May through September of each year at plants in and/or near those nonattainment On December 30, 2002, the Sierra Club, Physicians for areas. Seven generating plants in the Atlanta area are Social Responsibility, Georgia ForestWatch, and one currently subject to those requirements, the most recent individual filed a civil suit in the U.S. District Court in of which went into effect in 2003. Construction Georgia against the Company for alleged violations of expenditures for compliance with the nitrogen oxide the Clean Air Act at four of the units at Plant Wansley. emission reduction requirements are estimated to be The civil action requests injunctive and declaratory $698 million, of which $17 million remains to be spent.

relief, civil penalties, a supplemental environmental project, and attorneys' fees. The Clean Air Act On September 26, 2003, the EPA published a final authorizes civil penalties of up to $27,500 per day, per rule effective January 1, 2004 reclassifying the Atlanta violation at each generating unit. This case is currently area from a "serious" to a "severe" nonattainment area scheduled for trial during the summer of 2004. See Note for the one-hour ozone air quality standard under Title I 3 to the financial statements under "Plant Wansley of the Clean Air Act. The attainment deadline is to be as Environmental Litigation" for additional information. expeditious as practicable but not later than November 15, 2005. If the Atlanta area fails to comply with the While the Company believes that it has complied one-hour ozone standard by the deadline, all major with applicable laws and regulations, an adverse sources of nitrogen oxides and volatile organic outcome could require payment of substantial penalties. compounds located in the nonattainment area, including The final outcome of this matter cannot now be the Company's plants McDonough and Yates, could be determined. subject to payment of annual emissions fees for nitrogen oxides emitted above 80 percent of the baseline period.

Environmental Statutes and Regulations The baseline period is expected to be the calendar year 2005. Based on average emissions at these units over The Company's operations are subject to extensive the past three years, such fees could reach $23 million regulation by state and federal environmental agencies annually. The final outcome of this matter will depend under a variety of statutes and regulations governing on the baseline period selected and the development, environmental media, including air, water, and land approval, and implementation of applicable regulations

• resources. Compliance with these environmental including new regulations for the eight-hour ozone air requirements will involve significant capital and quality standard.

operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. To help ozone nonattainment areas attain the one-Environmental costs that are known and estimable at this hour ozone standard, the EPA issued regional nitrogen time are included in capital expenditures under "Capital oxide reduction rules in 1998. Those rules required 21 11

NIANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report states, including Georgia, to reduce and cap nitrogen Further reductions in sulfur dioxide and nitrogen oxide emissions from power plants and other large oxides could also be required under the EPA's Regional industrial sources. As a result of litigation challenging Haze rules. The Regional Haze rules require states to the rule, the courts required the EPA to complete a establish Best Available Retrofit Technology (BART) separate rulemaking before the requirements can be standards for certain sources that contribute to regional applied in Georgia. The final EPA rules have not been haze. The Company has a number of plants that could issued in Georgia. The impact of this rule on the be subject to these rules. The EPA's regional haze Company will depend on the form in which it is program calls for states to submit SIPs in 2007. The finalized and cannot be determined at this time. SIPs must contain emission reduction strategies for implementing BART and achieving progress toward the In July 1997, the EPA revised the national ambient Clean Air Act's visibility improvement goal. In 2002, air quality standards for ozone and particulate matter. however, the U.S. Court of Appeals for the District of These revisions made the standards significantly more Columbia Circuit vacated and remanded the BART stringent. In the subsequent litigation of these standards, provisions of the federal Regional Haze rules to the EPA the U.S. Supreme Court found the EPA's for further rulemaking. The EPA has entered into an implementation program for the new eight-hour ozone agreement that requires proposed revised rules in April standard unlawful and remanded it to the EPA for 2004 and final rules in 2005. Because new BART rules further rulemaking. During 2003, the EPA proposed have not been developed and state visibility assessments implementation rules designed to address the court's for progress are only beginning, it is not possible to concerns. The EPA plans to designate areas as determine the effect of these rules on the Company at attainment or nonattainment with the new eight-hour this time.

ozone standard in April 2004 and with the new fine particulate matter standard by the end of 2004. These The EPA's Compliance Assurance Monitoring designations will be based on air quality data for 2001 (CAM) regulations under Title V of the Clean Air Act through 2003. Several areas within the Company's require that monitoring be performed to ensure service area are likely to be designated nonattainment compliance with emissions limitations on an ongoing under these standards. State implementation plans basis. In 2004 and 2005, a number of the Company's (SlPs), including new emission control regulations plants will likely be subject to CAM requirements for at necessary to bring those areas into attainment, could be least one pollutant, in most cases, particulate matter.

required as early as 2007. Those SlPs could require The Company is in the process of developing CAM reductions in sulfur dioxide emissions and could require plans. Because the plans are still under development, further reductions in nitrogen oxide emissions from the Company cannot determine the costs associated with power plants. If so, reductions could be required implementation of the CAM regulations. Actual sometime after 2007. The impact of any new standards ongoing monitoring costs are expensed as incurred and will depend on the development and implementation of are not material for any year presented.

applicable regulations and 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 boilers. The proposal solicits comments on two possible Interstate Air Quality Rule 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 by 2005. If finalized by the end of 2004, and compliance could be finalized, the rule could modify or supplant other SIP required as early as 2007. Because the regulations have requirements for attainment of the fine particulate matter not been finalized, the impact on the Company cannot be standard and the eight-hour ozone standard. The impact determined at this time.

of this rule on the Company will depend upon the specific requirements of the final rule and cannot be Several major bills to amend the Clean Air Act to determined at this time. impose more stringent emissions limitations on power plants have been proposed by Congress. Three of these, 12

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report the Bush Administration's Clear Skies Act, the Clean and entrainment of fish and fish larvae at power plants' Power Act of 2003, and the Clean Air Planning Act of cooling water intake structures. On February 16, 2004, 2003, propose to further limit power plant emissions of the EPA finalized these rules. These rules will require sulfur dioxide, nitrogen oxides, and mercury. The latter numerous biological studies, and, perhaps, retrofits to two bills also propose to limit emissions of carbon some intake structures at existing power plants. The dioxide. The cost impacts of such legislation would impact of these new rules will depend on the results of depend upon the specific requirements enacted and studies and analyses performed as part of the rules' cannot be determined at this time. implementation.

Domestic efforts to limit greenhouse gas emissions The Company is also planning to install cooling have been spurred by international discussions towers at some of its facilities to cool water prior to surrounding the Framework Convention on Climate discharge under the Clean Water Act. Cooling towers Change and specifically the Kyoto Protocol, which for two plants near Atlanta are scheduled for completion proposes international constraints on the emissions of in 2004 and 2008 at an estimated total of $160 million, greenhouse gases. The Bush Administration does not of which $90 million remains to be spent. Also, the support U.S. ratification of the Kyoto Protocol or other Company is conducting a study of the aquatic mandatory carbon dioxide reduction legislation and has environment at another facility to determine if additional instead announced a new voluntary climate initiative, controls are necessary.

known as Climate VISION, which seeks an 18 percent reduction by 2012 in the rate of greenhouse gas In addition, under the Clean Water Act, the EPA and emissions relative to the dollar value of the U.S. the State of Georgia Environmental Protection Division economy. Through Southern Company, the Company is (EPD) are developing total maximum daily loads involved in a voluntary electric utility industry sector (TMDLs) for certain impaired waters. Establishment of climate change initiative in partnership with the maximum loads by the EPA or EPD may result in government. The electric utility sector has pledged to lowering permit limits for various pollutants and a reduce its greenhouse gas intensity 3 to 5 percent over requirement to take additional measures to control non-the next decade, and is in the process of developing a point source pollution (e.g., storm water runoff) at memorandum of understanding with the Department of facilities that discharge into waters for which TMDLs Energy (DOE) to cover this voluntary program. are established. Because the effect on the Company will depend on the actual TMDLs and permit limitations The Company must comply with other established by the implementing agency, it is not environmental laws and regulations that cover the possible to determine the effect on the Company at this handling and disposal of waste and releases of hazardous time.

substances. Under these various laws and regulations, the Company could incur substantial costs to clean up Several major pieces of environmental legislation properties. The Company conducts studies to determine are periodically considered for reauthorization or the extent of any required cleanup and has recognized in amendment by Congress. These include: the Clean Air its financial statements the costs to clean up and monitor Act; the Clean Water Act; the Comprehensive known sites. Amounts expensed for cleanup and; Environmental Response, Compensation, and Liability ongoing monitoring costs were not material for any year Act; the Resource Conservation and Recovery Act; the presented. The Company may be liable for a portion or Toxic Substances Control Act; the Emergency Planning all required cleanup costs for additional sites that may & Community Right-to-Know Act; and the Endangered require environmental remediation. Under GPSC Species Act.

ratemaking provisions, $21 million has been deferred in a regulatory liability account for use in meeting future Compliance with possible additional federal or state environmental remediation costs. See Note 3 to the legislation or regulations related to global climate financial statements under "Potentially Responsible change, electromagnetic fields, or other environmental Party Status" for information regarding the Company's and health concerns could also significantly affect the potentially responsible party status at sites in Georgia. Company. The impact of any new legislation, changes to existing legislation, or environmental regulations Under the Clean Water Act, the EPA has been could affect many areas of the Company's operations.

developing new rules aimed at reducing impingement 13

MANAGENIENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report The full impact of any such changes cannot, however, be Representatives but remains pending before the Senate.

determined at this time. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC FERC Matters will move forward with any part or all of the proposed rule. Any impact of this proposal on the Company will Transmission depend on the form in which the final rule may be ultimately adopted. However, the Company's financial In December 1999, the Federal Energy Regulatory statements could be adversely affected by changes in the Commission (FERC) issued its final rule (Order 2000) transmission regulatory structure in its regional power on Regional Transmission Organizations (RTOs). Order market.

2000 encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Through Southern Market-BasedRate Authority Company, the Company worked with a number of utilities in the Southeast to develop a for-profit RTO The Company has obtained FERC approval to sell power known as SeTrans. In 2002, the sponsors of SeTrans to non-affiliates at market-based prices under specific established a Stakeholder Advisory Committee to contracts. Through SCS, as agent, the Company also has provide input into the development of the RTO from FERC authority to make short-term opportunity sales at other sectors of the electric industry, as well as market rates. Specific FERC approval must be obtained consumers. During the development of SeTrans, state with respect to a market-based contract with an affiliate.

regulatory authorities expressed concern over certain In November 2001, the FERC modified the test it uses to aspects of the FERC's policies regarding RTOs. In consider utilities' applications to charge market-based December 2003, the SeTrans sponsors announced that rates and adopted a new test called the Supply Margin they would suspend work on SeTrans because the Assessment (SMA). The FERC applied the SMA to regulated utility participants, including the Company, several utilities, including Southern Company's retail had determined that it was highly unlikely to obtain operating companies, and found them to be "pivotal support of both federal and state regulatory authorities. suppliers" in their control area market and ordered the Any impact of the FERC's rule on the Company will implementation of several mitigation measures. SCS, on depend on the regulatory reaction to the suspension of behalf of the Company and the other retail operating SeTrans and future developments, which cannot now be companies, sought rehearing of the FERC order and the determined. FERC delayed implementation of certain mitigation measures. SCS, on behalf of the Company and the other In July 2002, the FERC issued a notice of proposed retail operating companies, submitted comments to the rulemaking regarding open access transmission service FERC in 2002 regarding these issues. In December and standard electricity market design. The proposal, if 2003, the FERC issued a staff paper discussing adopted, would among other things: (1) require alternatives and held a technical conference in January transmission assets of jurisdictional utilities to be 2004. The Company anticipates that the FERC will operated by an independent entity; (2) establish a address the requests for rehearing in the near future.

standard market design; (3) establish a single type of Regardless of the outcome of the SMA proposal, the transmission service that applies to all customers; (4) FERC retains the ability to modify or withdraw the assert jurisdiction over the transmission component of authorization for any seller to sell at market-based rates, bundled retail service; (5) establish a generation reserve if it determines that the underlying conditions for having margin; (6) establish bid caps for day ahead and spot such authority are no longer applicable. The final energy markets; and (7) revise the FERC policy on the outcome of this matter will depend on the form in which pricing of transmission expansions. Comments on the the SMA test and mitigation measures rules may be proposal were submitted by many interested parties, ultimately adopted and cannot be determined at this including Southern Company, and the FERC has time.

indicated that it has revised certain aspects of the proposal in response to public comments. Proposed Purchased power agreements (PPAs) by the energy legislation would prohibit the FERC from issuing Company and Savannah Electric for Southern Power's the final rule before October 31, 2006, and from making Plant McIntosh capacity were certified by the GPSC in any final rule effective before December 31, 2006. That December 2002 after a competitive bidding process. In legislation has been approved by the House of April 2003, Southern Power applied for FERC approval 14

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report of the PPAs. Interveners have made filings in opposition In accordance with Financial Accounting Standards of the FERC's acceptance of the PPAs, alleging that the Board (FASB) Statement No. 87, Employers' PPAs do not meet the applicable standards for market- Accounting for Pensions, the Company recorded non-based rates between alliliates. In July 2003, the FERC cash pension income, before tax, of approximately $54 accepted the PPAs to become effective as scheduled on million, $59 million, and $60 million in 2003, 2002, and June 1, 2005, subject to refund, and ordered that 2001, respectively. Future pension income is dependent hearings be held. For additional information, see Note 3 on several factors including trust earnings and changes to the financial statements under "FERC Matters." to the plan. The decline in pension income is expected to continue and to become an expense by as early as Other Matters 2007. Postretirement benefit costs for the Company were $41 million, $43 million and $43 million in 2003, The Company is currently operating under a GPSC 2002, and 2001, respectively, and are expected to trend approved three-year retail rate order ending December upward. A portion of pension and postretirement benefit 31, 2004. Under the terms of the order, earnings are costs is capitalized based on construction-related labor evaluated annually against a retail return on common charges. For the Company, pension income and equity range of 10 percent to 12.95 percent. Two-thirds postretirement benefit costs are a component of the of any earnings above the 12.95 percent return are regulated rates and generally do not have a significant applied to rate refunds with the remaining one-third long-term effect on net income. For additional retained by the Company. The Company is required to information, see Note 2 to the financial statements.

file a general rate case on July 1, 2004, in response to which the GPSC would be expected to determine On December 8, 2003, President Bush signed into whether the rate order should be continued, modified, or law the Medicare Prescription Drug, Improvement, and discontinued. See Note 3 to the financial statements Modernization Act of 2003 (Medicare Act). The under "Retail Rate Orders" for additional information. Medicare Act introduces a prescription drug benefit for Medicare-eligible retirees starting in 2006, as well as a The Company has entered into various long-term federal subsidy to plan sponsors like the Company that PPAs which will result in higher capacity and operating provide prescription drug benefits. In accordance with and maintenance payments in future years. These FASB Staff Position No. 106-1, the Company has agreements have been certified by the GPSC under elected to defer recognizing the effects of the Medicare Georgia's Integrated Resource Plan statute. Once Act for its postretirement plans under FASB Statement certified, these costs are recoverable in rates under the No. 106, Employers' Accounting for Postretirement statute. See Notes 3 and 7 to the financial statements Benefits Other than Pension until authoritative guidance under "Retail Rate Orders" and "Fuel and Purchased on accounting for the federal subsidy is issued or until a Power Commitments," respectively, for additional significant event occurs that would require information. remeasurement of the plans' assets and obligations. The Company anticipates that the benefits it pays after 2006 On December 24,2002, the GPSC approved an will be lower as a result of the Medicare Act; however, order allowing the Company to implement a natural gas the retiree medical obligations and costs reported in Note and oil procurement and hedging program effective 2 to the financial statements do not reflect these changes.

January 1, 2003. This order allows the Company to use The final accounting guidance could require changes to financial instruments to hedge price and commodity risk previously reported information.

associated with these fuels. The order limits the program in terms of time, volume, dollars, and physical Nuclear security legislation was recently introduced amounts hedged. The costs of the program, including and considered in Congress both as a free-standing bill any net losses, are recovered as a fuel cost through the in the Senate and as a part of comprehensive energy fuel cost recovery mechanism. Annual net financial legislation in a House-Senate Conference Report.

gains from the hedging program will be shared with the Neither of the proposals ha's been enacted. The Nuclear retail customers receiving 75 percent and the Company Regulatory Commission (NRC) also has ordered retaining 25 percent of the net gains. There were no net additional security measures for licensees in 2003. The gains in 2003. Company is in the process of implementation and must be in full compliance with these orders by October 29, 2004. The requirements of the latest orders will have an 15

MANAGENIENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report impact on the Company's nuclear power plants and regulatory agencies set the rates the Company is result in increased operation and maintenance expenses permitted to charge customers based on allowable as well as additional capital expenditures. The precise costs. As a result, the Company applies FASB impact of the new requirements will depend upon the Statement No. 71, Accounting for the Effects of details of the implementation of the new requirements, Certain Types of Regulation. Through the ratemaking which have not been finalized. process, the regulators may require the inclusion of costs or revenues in periods different than when they The Georgia General Assembly has recently adopted would be recognized by a non-regulated company.

legislation that changes the law concerning This treatment may result in the deferral of expenses and the recording of related regulatory assets based on condemnation of land for electric transmission lines. anticipated future recovery through rates or the The legislation requires that a utility planning to deferral of gains or creation of liabilities and the construct or expand a transmission line hold public recording of related regulatory liabilities. The meetings in each county where the line would be located application of Statement No. 71 has a further effect on and that the utility attempt to negotiate a settlement with the Company's financial statements as a result of the each affected property owner. The legislation also estimates of allowable costs used in the ratemaking provides for the reconveyance of property interests that process. These estimates may differ from those are condemned for a transmission line but are not used actually incurred by the Company; therefore, the for that purpose within a specified number of years. The accounting estimates inherent in specific costs such as legislation, unless vetoed by Governor Perdue, will depreciation, nuclear decommissioning, and pension become effective on July 1, 2004. and postretirement benefits have less of a direct impact on the Company's results of operations than The Company is involved in various matters being they would on a non-regulated company.

litigated, regulatory matters, and related issues that could affect future earnings. See Note 3 to the financial As reflected in Note I to the financial statements under "Regulatory Assets and Liabilities," significant statements for information regarding material issues.

regulatory assets and liabilities have been recorded.

Management reviews the ultimate recoverability of ACCOUNTING POLICIES these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse Application of Critical Accounting Policies and legislation and judicial or regulatory actions could Estimates materially impact the amounts of such regulatory assets and liabilities and could adversely impact the The Company prepares its financial statements in Company's financial statements.

accordance with accounting principles generally accepted in the United States. Significant accounting Contingent Obligations policies are described in Note 1 to the financial statements. In the application of these policies, The Company is subject to a number of federal and certain estimates are made that may have a material state laws and regulations, as well as other factors and impact on the Company's results of operations and conditions that potentially subject it to environmental, related disclosures. Different assumptions and litigation, income tax, and other risks. See "Future measurements could produce estimates that are Earnings Potential" and Note 3 to the financial significantly different from those recorded in the statements for more information regarding certain of financial statements. Senior management has these contingencies. The Company periodically discussed the development and selection of the critical evaluates its exposure to such risks and records accounting policies and estimates described below reserves for those matters where a loss is considered with the Controls and Compliance Committee of the probable and reasonably estimable in accordance with Company's Board of Directors and the Audit generally accepted accounting principles. The Committee of Southern Company's Board of adequacy of reserves can be significantly affected by Directors. external events or conditions that can be unpredictable; thus, the ultimate outcome of such Electric Utility Regulation matters could materially affect the Company's financial statements. These events or conditions The Company is subject to retail regulation by the include the following:

GPSC and wholesale regulation by the FERC. These 16

MANAGENMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report

• Changes in existing state or federal regulation by continue to be exempt from fair value accounting governmental authorities having jurisdiction over requirements or to qualify as cash flow hedges, with the air quality, water quality, control of toxic related gains and losses deferred in other comprehensive substances, hazardous and solid wastes, and other income. The implementation of Statement No. 149 did environmental matters. not have a material effect on the Company's financial

• Changes in existing income tax regulations or statements.

changes in Internal Revenue Service interpretations of existing regulations. In July 2003, the Emerging Issues Task Force (EITF)

• Identification of additional sites that require of the FASB issued EITF No. 03-11, which became environmental remediation or the filing of other complaints in which the Company may be asserted effective on October 1, 2003. The standard addresses to be a potentially responsible party. the reporting of realized gains and losses on derivative

• Identification and evaluation of other potential instruments and is being interpreted to require book outs lawsuits or complaints in which the Company may to be recorded on a net basis in operating revenues.

be named as a defendant. Adoption of this standard did not have a material impact

• Resolution or progression of existing matters on the Company's financial statements.

through the legislative process, the court systems, the EPA, or the EPD. FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was originally issued in New Accounting Standards January 2003, requires the primary beneficiary of a variable interest entity to consolidate the related assets Prior to January 2003, the Company accrued for the and liabilities. In December 2003, the FASB revised ultimate cost of retiring most long-lived assets over the Interpretation No. 46 and deferred the effective date until life of the related asset through depreciation expense. March 31, 2004 for interests held in variable interest FASB Statement No. 143, Accounting for Asset entities other than special purpose entities.

Retirement Obligations, established new accounting and reporting standards for legal obligations associated with Current analysis indicates that the trusts established the ultimate cost of retiring long-lived assets. The by the Company to issue preferred securities are variable present value of the ultimate costs for an asset's future interest entities under Interpretation No. 46, and that the retirement is recorded in the period in which the liability Company is not the primary beneficiary of the trusts. If is incurred. The costs are capitalized as part of the this conclusion is finalized, effective March 31, 2004, related long-lived asset and depreciated over the asset's the trust assets and liabilities -- including the preferred useful life. Additionally, non-regulated companies are securities issued by the trusts -- will be deconsolidated.

no longer permitted to continue accruing future The investments in the trusts and the loans from the retirement costs for long-lived assets that they do not trusts to the Company will be reflected as equity method have a legal obligation to retire. For additional investments and as long-term notes payable to affiliates, information regarding the impact of adopting this respectively, on the Balance Sheets. Based on standard effective January 1, 2003, see Note I to the December 31, 2003 values, this treatment would result in financial statements under "Asset Retirement an increase of approximately $29 million to both total Obligations and Other Costs of Removal." assets and liabilities. See Note 6 to the financial statements under "Mandatorily Redeemable Preferred FASB Statement No. 149, Amendment of Statement Securities" for additional information.

133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and In May 2003, the FASB issued Statement No. 150, reporting for derivative instruments, became effective Accounting for Certain Financial Instruments with generally for financial instruments entered into or Characteristics of Both Liabilities and Equity, which modified after June 30, 2003. Current interpretations of requires classification of certain financial instruments Statement No. 149 indicate that certain electricity within its scope, including shares that are mandatorily forward transactions subject to unplanned netting -- redeemable, as liabilities. Statement No. 150 was including those typically referred to as "book outs" -- effective for financial instruments entered into or may only qualify as cash flow hedges if an entity can modified after May 31, 2003, and otherwise on July 1, demonstrate that physical delivery or receipt of power 2003. In accordance with Statement No. 150, the occurred. The Company's forward electricity contracts Company's mandatorily redeemable preferred securities 17

MIANAGENIENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report are reflected as liabilities on the Balance Sheets. The encumbrances on the Company's property were adoption of Statement No. 150 had no impact on the discharged. As a result, the Company cannot issue any Statements of Income and Cash Flows. securities pursuant to this indenture. See "First Mortgage Bond Indenture" under Note 6 to the financial FINANCIAL CONI)ITION AND) LIOUIDITY statements for additional information.

Overview The Company obtains financing separately without credit support from any affiliate. The Southern Over the last several years, the Company's financial Company system does not maintain a centralized cash or condition has remained stable with emphasis on cost money pool. Therefore, funds of the Company are not control measures combined with significantly lower cost commingled with funds of any other company. In of capital, achieved through the refinancing and/or accordance with the Public Utility Holding Company redemption of higher-cost long-term debt, preferred Act, most loans between affiliated companies must be stock and preferred securities. The Company operated at approved in advance by the Securities and Exchange high levels of reliability while achieving industry- Commission (SEC).

leading customer satisfaction levels and continuing to have retail prices below the national average. The Company's current liabilities frequently exceed current assets because of the continued use of short-term In 2003, gross utility plant additions were $743 debt as a funding source to meet cash needs which can million. These additions were primarily related to fluctuate significantly due to the seasonality of the transmission and distribution facilities and the purchase business.

of nuclear fuel and equipment to comply with environmental standards. The majority of funds needed To meet short-term cash needs and contingencies, for gross property additions for the last several years the Company had approximately $725 million of unused have been provided from operating activities. The credit arrangements with banks at the beginning of 2004.

Statements of Cash Flows provide additional details. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

The Company's ratio of common equity to total capitalization -- including short-term debt -- was 48.3 The Company may also meet short-term cash needs percent in 2003, 48.3 percent in 2002, and 47.7 percent through a Southern Company subsidiary organized to in 2001. See Note 6 to the financial statements for issue and sell commercial paper and extendible additional information. commercial notes at the request and for the benefit of the Company and the other Southern Company operating Sources of Capital companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and The Company expects to meet future capital are not commingled with proceeds from issuances for requirements primarily using funds generated from the benefits of any other operating company. The operating activities and equity funds from Southern obligations of each company under these arrangements Company and by the issuance of new debt securities, are several; there is no cross affiliate credit support. At term loans, and short-term borrowings. The Company December 31, 2003, the Company had outstanding $137 had S 137 million of GPSC approved financing authority million of commercial paper and no extendible as of December 31, 2003. The Company used this commercial notes.

remaining authority in February 2004. The type and timing of future financings will depend on market At the beginning of 2004, the Company had not used conditions and regulatory approval of additional any of its available credit arrangements. Bank credit financing authority. Recently, the Company has relied arrangements are as follows:

on the issuance of unsecured debt and preferred securities, in addition to unsecured pollution control Expires bonds issued for its benefit by public authorities, to meet Total Unused 2004 its long-term external financing requirements. (in millions)

$725 $725 $725 In February 2002, the Company defeased its first mortgage bond indenture and all related liens or 18

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report All of these credit arrangements allow for the commodity fuel prices and prices of electricity. To execution of term loans for an additional two year manage the volatility attributable to these exposures, the period. Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for Financing Activities the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and In 2003, the Company's financing costs increased due to hedging practices. Company policy is that derivatives the issuance of new debt during the year. New issues are to be used primarily for hedging purposes.

during 2001 through 2003 totaled $3.2 billion and Derivative positions are monitored using techniques that retirement or repayment of higher-cost securities totaled include market valuation and sensitivity analysis.

$2.4 billion.

To mitigate the Company's exposure to interest Composite financing rates for long-term debt, rates, the Company has entered into interest rate swaps preferred stock, and preferred securities for the years that were designed as cash flow hedges of variable rate 2001 through 2003, as of year-end, were as follows: debt or anticipated debt issuances. At December 31, 2003 the Company had no variable long-term debt 2003 2002 2001 outstanding that had not been hedged. Therefore, there Composite interest rate would be no effect on annualized interest expense if the on long-term debt 4.01% 4.47% 4.26% Company sustained a 100 basis point change in interest Composite preferred rates for all variable rate long-term debt. The Company stock dividend rate 4.60 4.60 4.60 is not aware of any facts or circumstances that would Composite preferred significantly affect such exposures in 2004. See Notes 1 securities distribution 6.35 6.35 7.49 and 6 to the financial statements under "Financial rate Instruments" for additional information.

Subsequent to December 31, 2003, the Company To mitigate residual risks relative to movements in has issued $550 million of new securities with the electricity prices, the Company enters into fixed price proceeds used primarily to retire higher coupon long- contracts for the purchase and sale of electricity through term debt and for construction and general corporate the wholesale electricity market and, to a lesser extent, purposes. into similar contracts for gas purchases. Fair value of changes in derivative energy contracts and year-end Credit Rating Risk valuations were as follows:

The Company does not have any credit agreements that Changes in Fair Value would require material changes in payment schedules or 2003 2002 terminations as a result of a credit rating downgrade. (in millions)

There are contracts that could require collateral -- but not Contracts beginning of year $0.1 $0.4 accelerated payment -- in the event of a credit rating Contracts realized or settled (0.4) 0.9 change to below investment grade. These contracts are New contracts at inception - -

primarily for physical electricity purchases and sales, Changes in valuation techniques -

fixed-price physical gas purchases, and agreements Current period changes 3.5 (1.2) covering interest rate swaps. At December 31, 2003, the Contracts end of year $3.2 $0.1 maximum potential collateral requirements were approximately $227 million. At December 31, 2003, Source of 2003 Year-End Valuation Prices there were no material collateral requirements for the gas Total Maturity purchase contracts or other financial instrument agreements. Fair Value Year 1 1-3 Years (in millions)

Market Price Risk Actively quoted $3.2 $2.8 $0.4 External sources - - -

Due to cost-based regulations the Company has limited Models and other exposure to market volatility in interest rates, methods Contracts end of year $3.2 $2.8 $0.4 19

MANAGE'MENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report Unrealized gains and losses from mark to market The Company has no generating plants under adjustments on derivative contracts related to the construction. However, construction related to new Company's fuel hedging programs are recorded as transmission and distribution facilities and capital regulatory assets and liabilities. Realized gains and improvements to existing generation, transmission losses from these programs are included in fuel expense and distribution facilities, including those needed to and are recovered through the Company's fuel cost meet the environmental standards previously recovery mechanism. Gains and losses on derivative discussed, are ongoing.

contracts that are not designated as hedges are As a result of requirements by the NRC, the recognized in the income statement as incurred. At Company has established external trust funds for nuclear December 31, 2003, the fair value of derivative energy decommissioning costs. For additional information, see contracts reflected in the financial statements was as Note 1 to the financial statements under "Nuclear follows:

Decommissioning." Also as discussed in Note I to the financial statements under "Revenues and Fuel Costs,"

Amounts (in mnillions) in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be Regulatory liabilities, net $3.2 used for the decontamination and decommissioning of Other comprehensive income its nuclear fuel enrichment facilities.

Net income Total fair value $3.2 In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement Gains (losses) recognized in income in 2003, 2002, benefits to substantially all employees and funds trusts to and 2001 were not material. The Company is exposed to the extent required by the GPSC and the FERC.

market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company's policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody's and Standard & Poor's or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under "Financial Instruments."

Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to be $747 million for 2004, $812 million for 2005, and $1,043 million for 2006. Environmental expenditures included in these amounts are $91 million,

$113 million, and $316 million for 2004, 2005, and 2006, 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.

20

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report Other funding requirements related to obligations leases, and other purchase commitments are as associated with scheduled maturities of long-term follows. See Notes 1, 6, and 7 to the financial debt and preferred securities, as well as the related statements for additional information.

interest and distributions, preferred stock dividends, 2005- 2007- After 2004 2006 2008 2008 Total (in millions)

Long-term debt and preferred securities(a)-

Principal $ 2 $ 605 $ 306 $3,792 $ 4,705 Interest and distributions 211 409 363 3,885 4,868 Preferred stock dividends(b) 1 1 1 - 3 Operating leases 34 56 44 72 206 Purchase commitments(C) --

Capital (d) 718 1,815 2,286 - 4,819 Coal and nuclear fuel 1,321 1,940 975 183 4,419 Natural gas(') 156 297 280 1,625 2,358 Purchased power 293 828 852 2,573 4,546 Trusts(f)-

Nuclear decommissioning 9 17 17 95 138 Postretirement benefits 9 21 - - 30 DOE assessments 3 7 - - 10 Total $2,757 $5,996 $5,124 $12,225 $26,102 (a) All amounts are reflected based on final maturity dates. The Company will 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, 2004, 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 $1.2 billion, $1.3 billion, and $1.2 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, 2003, 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 future prices at December 31, 2003.

(f) Projections of nuclear decommissioning trust contributions are based on the current GPSC order which will be reevaluated in the Company's upcoming rate case and is subject to change. 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.

21

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2003 Annual Report Cautionary Statement Regarding Forward-Looking Information The Company's 2003 Annual Report includes forward-looking statements in addition to historical information.

Forward-looking information includes, among other things, statements concerning the estimated construction and other expenditures and the Company's projections for energy sales and its goals for future generating capacity and earnings growth. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could,"

should," "expects," ".plans,""anticipates," "believes," "estimates,' projects," "predicts," "potential," or "continue" or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental, 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;

• the impact of fluctuations in commodity prices, interest rates, and customer demand;

• 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 pending and future rate cases and negotiations;

• effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy;

• internal restructuring or other restructuring options that may be pursued;

• potential business strategies, including acquisitions or dispositions of assets, 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 effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents;

• 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;

• weather and other natural phenomena;

• the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents;

• the effect of accounting pronouncements issued periodically by standard-setting bodies; and

• other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the SEC.

22

STATEMENTS OF INCOME For the Years Ended December 31, 2003, 2002, and 2001 Georgia Power Company 2003 Annual Report 2003 2002 2001 (in thousands)

Operating Revenues:

Retail sales S4,309,972 $4,288,097 $4,349,312 Sales for resale --

Non-affiliates 259,376 270,678 366,085 Affiliates 174,855 98,323 99,411 Other revenues 169,304 165,362 150,986 Total operating revenues 4,913,507 4,822,460 4,965,794 Operating Expenses:

Fuel 1,103,963 1,002,703 939,092 Purchased power --

Non-affiliates 258,621 264,814 442,196 Affiliates 516,944 419,839 329,232 Other operations 827,972 848,436 810,043 Maintenance 419,206 476,962 430,413 Depreciation and amortization 349,984 403,507 600,631 Taxes other than income taxes 212,827 201,857 202,483 Total operating expenses 3,689,517 3,618,118 3,754,090 Operating Income 1,223,990 1,204,342 1,211,704 Other Income and (Expense):

Allowance for equity funds used during construction 10,752 7,622 9,081 Interest income 15,625 3,857 4,264 Interest expense, net of amounts capitalized (182,583) (168,391) (183,879)

Distributions on mandatorily redeemable preferred securities (59,675) (62,553) (59,104)

Other income (expense), net (10,551) (9,259) (7,719)

Total other income and (expense) (226,432) (228,724) (237,357)

Earnings Before Income Taxes 997,558 975,618 974,347 Income taxes 366,311 357,319 363,599 Earnings Before Cumulative Effect of Accounting Change 631,247 618,299 610,748 Cumulative effect of accounting change--

less income taxes of S162 - - 257 Net Income 631,247 618,299 611,005 Dividends on Preferred Stock 670 670 670 Net Income After Dividends on Preferred Stock $630.577 $ 617,629 $ 610,335 The accompanying notes are an integral part of these financial statements.

23

BALANCE SHEETS At December 31, 2003 and 2002 Georgia Power Company 2003 Annual Report Assets 2003 2002 (inthousands)

Current Assets:

Cash and cash equivalents S 8,699 S 16,873 Receivables --

Customer accounts receivable 261,771 302,995 Unbilled revenues 117,327 104,454 Under recovered regulatory clause revenues 151,447 117,580 Other accounts and notes receivable 101,783 122,585 Affiliated companies 52,413 40,501 Accumulated provision for uncollectible accounts (5,350) (5,825)

Fossil fuel stock, at average cost 137,537 120,048 Materials and supplies, at average cost 271,040 263,364 Vacation pay 50,150 53,677 Prepaid expenses 46,157 42,809 Other 83 436 Total current assets 1,193,057 1,179,497 Property, Plant, and Equipment:

In service 18,171,862 17,222,661 Less accumulated provision for depreciation 6,898,725 6,533,412 11,273,137 10,689,249 Nuclear fuel, at amortized cost 129,056 119,588 Construction work in progress 341,783 667,581 Total property, plant, and equipment 11,743,976 11,476,418 Other Property and Investments:

Equity investments in unconsolidated subsidiaries 38,714 36,167 Nuclear decommissioning trusts, at fair value 423,319 346,870 Other 37,142 28,612 Total other property and investments 499,175 411,649 Deferred Charges and Other Assets:

Deferred charges related to income taxes 509,887 524,510 Prepaid pension costs 405,164 341,944 Unamortized debt issuance expense 75,245 67,362 Unamortized loss on reacquired debt 177,707 178,590 Other 177,817 162,686 Total deferred charges and other assets 1,345,820 1,275,092 Total Assets S14.782.028 $14,342:656 The accompanying notes are an integral part of these financial statements.

24

BALANCE SHEETS At December 31, 2003 and 2002 Georgia Power Company 2003 Annual Report Liabilities and Stockholder's Equity 2003 2002 (in thousands)

Current Liabilities:

Securities due within one year S 2,304 $ 322,125 Notes payable 137,277 357,677 Accounts payable -

Affiliated 121,928 135,260

Other 238,069 314,327 Customer deposits 103,756 94,859 Accrued taxes --

Income taxes 107,532 20,245 Other 166,892 134,269 Accrued interest 70,844 59,608 Accrued vacation pay 38,206 42,442 Accrued compensation 134,004 130,893 Other 105,234 112,131 Total current liabilities 1,226,046 1,723,836 -

Long-term debt (See accompanying statements) = 3,762,333 3,109.619 Mandatorily redeemable preferred securities (See accompanying statements) ,

JA4 Ann onvvuv 940,000 Deferred Credits and Other Liabilities:

Accumulated deferred income taxes 2,303,085 2,176,438 Deferred credits related to income taxes 186,625 208,410 Accumulated deferred investment tax credits 312,506 324,994 Employee benefit obligations 295,788 248,415 Asset retirement obligations 475,585 Other cost of removal obligations 412,161 800,117 Miscellaneous regulatory liabilities 249,687 331,241 Other 63,432 30,570 Total deferred credits and other liabilities = 4,298,869 4,120,185 =

Total liabilities 10,227,248 9,893,640 Preferred stock (See accompanying statements) 14,569 14,569 Common stockholder's equity (See accompanying statements) 4,540,211 4,434,447 Total Liabilities and Stockholder's Eguity $14782.,028 P w v 4147 Be_

49656

• vv Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

25

STATEMENTS OF CAPITALIZATION At December 31, 2003 and 2002 Georgia Power Company 2003 Annual Report 2003 2002 2003 2002 (in thousands) (percent of total)

Long-Term Debt:

Long-term notes payable --

5.25% to 5.75% due 2003 5 - $ 320,000 5.50% due December 1, 2005 150,000 150,000 6.20% due February 1, 2006 150,000 150,000 4.875% due July 15, 2007 300,000 300,000 5.125% to 6.875% due 2011-2047 1,100,000 745,000 Variable rate (1.25% to 1.30% at 1/1/04) 300,000 Total long-term notes payable 2,000,000 1,665.000 Other long-term debt --

Pollution control revenue bonds --

Non-collateralized:

1.20% to 5.45% due 2012-2034 812,560 751,760 Variable rates (1.10% to 1.40% at 1/1/04) due 2011-2032 873,330 934,130 Total other long-term debt 1,685,890 1,685,890 Capitalized lease obligations 79,286 81,411 Unamortized debt premiumn (discount), net (539) (557)

Total long-term debt (annual interest requirement-- $151.2 million) 3,764,637 3,431,744 Less amount due within one year 2,304 322,125 Long-term debt excluding amount due within one year 3,762,333 3,109,619 40.6% 36.5%

Mandatorily Redeemable Preferred Securities:

$25 liquidation value --

6.85% due 2029 200,000 200,000 7.125% due 2042 440,000 440,000

$1,000 liquidation value --

4.875% due 2042* 300,000 300,000 Total (annual distribution requirement -- $59.7 million) 940,000 940,000 10.2 11.1 Cumulative Preferred Stock:

$100 stated value at 4.60% 14,569 14,569 Total (annual dividend requirement -- 50.7 million) 14,569 14,569 0.2 0.2 Common Stockholder's Equity:

Common stock, without par value --

Authorized - 15,000,000 shares Outstanding - 7,761,500 shares 344,250 344,250 Paid-in capital 2,208,498 2,156,040 Premium on preferred stock 40 40 Retained earnings 2,010,297 1,945,520 Accumulated other comprehensive income (loss) (22,874) (11,403)

Total common stockholder's equity 4,540,211 4,434,447 49.0 52.2 Total Canitalization $9.257.113 58.498.635 100.0% 100.0%

• The fixed rate thereafter is determined through remarketings for specific periods of varying length at floating rates determined by reference to 3-month LIBOR plus 3.05%.

The accompanying notes are an integral part of these financial statements.

26

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2003, 2002, and 2001 Georgia Power Company 2003 Annual Report Premium on Other Common Paid-In Preferred Retained Comprehensive Stock Capital Stock Earnings Income (loss) Total (in thousands)

Balance at December 31, 2000 5344,250 $2,117,497 $40 $1,787,757 $ - S4,249,544 Net income after dividends on preferred stock - - - 610,335 - 610,335 Capital distributions to parent company - (160,000) - - - (160,000)

Capital contributions from parent company - 225,060 - - - 225,060 Other comprehensive income (loss) - - - - (153) (153)

Cash dividends on common stock - - - (527,300) - (527,300)

Preferred stock transactions, net - - - (1) - (1)

Balance at December 31, 2001 344,250 2,182,557 40 1,870,791 (153) 4,397,485 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 2,156,040 40 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 $2,208,498 $40 S2,010,297 $(22,874) $4,540,211 The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2003, 2002, and 2001 Georgia Power Company 2003 Annual Report 2003 2002 2001 (in thousands)

Net income after dividends on preferred stock $630,577 $617,629 $610,335 Other comprehensive income (loss):

Change in additional minimum pension liability, net of tax of

$(5,133) and $(4,853), respectively (8,138) (7,693)

Cumulative effect of accounting change for qualifying hedges, net of tax of $180 - 286 Changes in fair value of qualifying hedges, net of tax of S(3,241), $(2,502) and $(277), respectively (5,550) (3,555) (439)

Less: Reclassification adjustment for amounts included in net income, net of tax of $ 1,208 and $0, respectively 2,217 (2) -

Total other comprehensive income (loss) (11,471) (11,250) (153)

Comprehensive Income $619,106 $606,379 $610.182 The accompanying notes arc an integral part of these financial statements.

27

STATEMENTS OF CASH[ FLOWS For the Years Ended December 31, 2003, 2002, and 2001 Georgia Power Company 2003 Annual Report 2003 2002 2001 (in thousands)

Operating Activities:

Net income $ 631,247 $ 618,299 $ 611,005 Adjustments to reconcile net income to net cash provided from operating activities --

Depreciation and amortization 390,201 411,435 697,143 Deferred income taxes and investment tax credits, net 230,221 65,550 (48,329)

Pension, postretirement, and other employee benefits (29,118) (64,771) (57,239)

Tax benefit of stock options 11,649 8,184 Settlement of interest rate hedges (11,250) 860 Other, net 2,768 (50,282) (43,458)

Changes in certain current assets and liabilities --

Receivables, net (4,870) 68,527 60,914 Fossil fuel stock (17,490) 82,711 (103,296)

Materials and supplies (7,677) 15,874 (15,628)

Other current assets (2,352) (18,880) 3,755 Accounts payable (49,598) 64,902 (15,406)

Accrued taxes 52,348 (6,540) 18,392 Other current liabilities 16,734 16,166 (46,691)

Net cash provided from operating activities 1,212,813 1,212,035 1,061,162 Investing Activities:

Gross property additions (742,810) (883,968) (1,389,751)

Cost of removal net of salvage (28,265) (60,912) (50,093)

Sales of property - 387,212 534,760 Change in construction payables, net ofjoint owner portion (32,223) (7,411) 24,457 Other 15,961 34,580 20,862 Net cash used for investing activities (787,337) (530,499) (859,765)

Financing Activities:

Increase (decrease) in notes payable, net (220,400) (389,860) 43,698 Proceeds --

Senior notes 1,000,000 500,000 600,000 Pollution control bonds - - 404,535 Mandatorily redeemable preferred securities - 740,000 Capital contributions from parent company 40,809 165,299 225,060 Redemptions --

First mortgage bonds - (1,860) (390,140)

Pollution control bonds - (7,800) (385,035)

Senior notes (665,000) (330,000)

Mandatorily redeemable preferred securities - (589,250)

Capital distributions to parent company - (200,000) (160,000)

Payment of preferred stock dividends (696) (721) (578)

Payment of common stock dividends (565,800) (542,900) (527,300)

Other (22,563) (30,831) (17,747)

Net cash used for financing activities (433,650) (687,923) (207,507)

Net Change in Cash and Cash Equivalents (8,174) (6,387) (6,110)

Cash and Cash Equivalents at Beginning of Period 16,873 23,260 29,370 Cash and Cash Equivalents at End of Period $ 8,699 $ 16,873 $ 23,260 Supplemental Cash Flow Information:

Cash paid during the period for --

Interest (net of S5,428, $9,368, and $38,331 capitalized, $215,463 $203,707 $234,456 respectively)

Income taxes (net of refunds) 145,048 326,698 381,995 The accompanying notes are an integral part of these financial statements.

28

NOTES TO FINANCIAL STATEMENTS Georgia Power Company 2003 Annual Report

1.

SUMMARY

OF SIGNIFICANT Commission (GPSC). The Company follows accounting ACCOUNTING POLICIES principles generally accepted in the United States and complies with the accounting policies and practices General prescribed by its regulatory commissions. The preparation of financial statements in conformity with The Company is a wholly owned subsidiary of Southern accounting principles generally accepted in the United Company, which is the parent company of five retail States requires the use of estimates and the actual results operating companies, Southern Power Company may differ from these estimates.

(Southern Power), Southern Company Services (SCS),

Southern Communications Services (Southern LINC), Certain prior years' data presented in the financial Southern Company Gas (Southern Company GAS), statements have been reclassified to conform with Southern Company Holdings (Southern Holdings), current year presentation.

Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and Affiliate Transactions indirect subsidiaries. The retail operating companies -

Alabama Power, the Company, Gulf Power, Mississippi The Company has an agreement with SCS under which Power, and Savannah Electric -- provide electric service the following services are rendered to the Company at in four Southeastern states. The Company operates as a direct or allocated cost: general and design engineering, vertically integrated utility providing electricity to retail purchasing, accounting and statistical analysis, finance customers within its traditional service area located and treasury, tax, information resources, marketing, within the State of Georgia and to wholesale customers auditing, insurance and pension administration, human in the Southeast. Southern Power constructs, owns, and resources, systems and procedures, and other services manages Southern Company's competitive generation with respect to business and operations and power pool assets and sells electricity at market-based rates in the operations. Costs for these services amounted to $303 wholesale market. Contracts among the retail operating million in 2003, $318 million in 2002, and $286 million companies and Southern Power -- related to jointly in 2001. Cost allocation methodologies used by SCS are owned generating facilities, interconnecting transmission approved by the SEC and management believes they are lines, or the exchange of electric power -- are regulated reasonable.

by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). The Company has an agreement with Southern SCS, the system service company, provides, at cost, Nuclear under which the following nuclear-related specialized services to Southern Company and services are rendered to the Company at cost: general subsidiary companies. Southern LINC provides digital executive and advisory services; general operations, wireless communications services to the retail operating management and technical services; administrative companies and also markets these services to the public services including procurement, accounting, employee within the Southeast. Southern Telecom provides fiber relations, and systems and procedures services; strategic cable services within the Southeast. Southern Company planning and budgeting services; and other services with GAS is a competitive retail natural gas marketer serving respect to business and operations. Costs for these customers in Georgia. Southern Holdings is an services amounted to $289 million in 2003, $301 million intermediate holding subsidiary for Southern Company's in 2002, and $281 million in 2001.

investments in synthetic fuels and leveraged leases and an energy services business. Southern Nuclear operates The Company has an agreement with Southern and provides services to Southern Company's nuclear Power under which the Company operates and maintains power plants. Southern Power owned plants Dahlberg, Franklin, and Wansley at cost. Reimbursements under these Southern Company is registered as a holding agreements with Southern Power amounted to $5.3 company under the Public Utility Holding Company Act million in 2003, $5.3 million in 2002 and $1.0 million in of 1935 (PUHCA). Both Southern Company and its 2001. These agreements arose from the transfer of subsidiaries are subject to the regulatory provisions of certain generation facilities to Southern Power in 2001 the PUHCA. The Company is also subject to regulation and 2002. See Note 7 under "Construction Program" for by the FERC and the Georgia Public Service additional information.

29

NOTES (continued) ceorgia Power Company 2003 Annual Report Southern Company holds a 30 percent ownership in under "Fuel and Purchased Power Commitments" for Alabama Fuel Products, LLC (AFP), which produces additional information.

synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides Revenues and Fuel Costs services for AFP. Under this agreement, the Company provides certain accounting functions, including Energy and other revenues are recognized as services are processing and paying fuel transportation invoices, and provided. Unbilled revenues are accrued at the end of the Company is reimbursed for its expenses. Amounts each fiscal period. Fuel costs are expensed as the fuel is billed under this agreement totaled approximately $38 used. Electric rates for the Company include provisions million in 2003. In addition, the Company purchases to adjust billings for fluctuations in fuel costs, fuel synthetic fuel from AFP for use at Plant Branch. Fuel hedging, the energy component of purchased power purchases totaled $91 million in 2003. costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts Effective June 2002, the Company entered into actually recovered in current rates.

purchased power agreements (PPAs) with Southern Power for capacity and energy. Purchased power costs The Company has a diversified base of customers.

in 2003 and 2002 amounted to $203 million and $128 No single customer or industry comprises 10 percent or million, respectively. Additionally, the Company more of revenues. For all periods presented, recorded $7 million and $12 million of prepaid capacity uncollectible accounts averaged less than I percent of expenses included in Other Deferred Charges and Other revenues despite an increase in customer bankruptcies.

Assets on the Balance Sheets at December 31, 2003 and 2002, respectively. See Note 7 under "Fuel and Fuel expense includes the amortization of the cost of Purchased Power Commitments" for additional nuclear fuel and a charge, based on nuclear generation, information. for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense The Company has an agreement with Gulf Power amounted to $74 million in 2003, $71 million in 2002, under which Gulf Power jointly owns a portion of Plant and $75 million in 2001. The Company has contracts Scherer. Under this agreement, the Company operates with the U.S. Department of Energy (DOE) that provide Plant Scherer and Gulf Power reimburses the Company for the permanent disposal of spent nuclear fuel. The for its proportionate share of the related expenses which DOE failed to begin disposing of spent nuclear fuel in were $5.6 million in 2003 and $4.5 million in 2002. The January 1998 as required by the contracts, and the Company has an agreement with Savannah Electric Company is pursuing legal remedies against the under which the Company jointly owns a portion of government for breach of contract. Sufficient pool Plant McIntosh. Under this agreement, Savannah storage capacity for spent fuel is available at Plant Electric operates Plant McIntosh and the Company Vogtle to maintain full-core discharge capability for reimburses Savannah Electric for its proportionate share both units into the year 2015. At Plant Hatch, an on-site of the related expenses which were $3.6 million in 2003 dry storage facility became operational in 2000 and can and $1.8 million in 2002. See Note 4 for additional be expanded to accommodate spent fuel through the life information. of the plant. Construction of an on-site dry storage facility at Plant Vogtle will begin in sufficient time to Also see Note 4 for information regarding the maintain pool full-core discharge capability.

Company's ownership in and purchased power agreement with Southiern Electric Generating Company. Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment The retail operating companies, including the Decontamination and Decommissioning Fund, which is Company, Southern Power, and Southern Company funded in part by a special assessment on utilities with GAS may jointly enter into various types of wholesale nuclear plants. The assessment is being paid over a 15-energy, natural gas and certain other contracts, either year period, which began in 1993. This fund will be directly or through SCS as agent. Each participating used by the DOE for the decontamination and company may be jointly and severally liable for the decommissioning of its nuclear fuel enrichment obligations incurred under these agreements. See Note 7 facilities. The law provides that utilities will recover 30

NOTES (continued)

Georgia Power Company 2003 Annual Report these payments in the same manner as any other fuel ended December 31, 2001. Regulatory assets and expense. The Company -- based on its ownership (liabilities) reflected in the Company's Balance Sheets at interest -- estimates its remaining liability at December December 31 relate to the following:

31, 2003 under this law to be approximately $10 million.

2003 2002 Note Income Taxes (in millions)

Deferred income tax charges $ 510 $ 525 (a)

The Company uses the liability method of accounting for Loss on reacquired debt 178 179 (b) deferred income taxes and provides deferred income Corporate building lease 54 54 (f) taxes for all significant income tax temporary Vacation pay 50 54 (d)

Postretirement benefits 23 25 (f) differences. Investment tax credits utilized are deferred DOE assessments 13 16 (c) and amortized to income over the average lives of the Generating plant outage costs 49 48 (f) related property. Other regulatory assets 1 7 (f)

Asset retirement obligation (16) -(a)

Regulatory Assets and Liabilities Other cost of removal obligations (412) (800) (a)

Accelerated cost recovery (111) (222) (e)

The Company is subject to the provisions of Financial Deferred income tax credits (187) (208) (a)

Accounting Standards Board (FASB) Statement No. 71, Environmental remediation reserve (21) (21) (f)

Accounting for the Effects of Certain Types of Purchased power (77) (63) (f)

Regulation. Regulatory assets represent probable future Other regulatory liabilities (3) (1) (f) revenues associated with certain costs that are expected Total $ 51 $ (26) to be recovered from customers through the ratemaking Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

process. Regulatory liabilities represent probable future (a) Asset retirement and removal liabilities are recorded, deferred reductions in revenues associated with amounts that are income taxes are recovered, and deferred tax liabilities are expected to be credited to customers through the amortized over the related property lives, which may range up ratemaking process. See Note 3 under "Retail Rate to 50 years. Asset retirement and removal liabilities will be Orders" for additional information regarding the settled and trued up following completion of the related activities.

disposition of the regulatory liability for the accelerated (b) Recovered over either the remaining life of the original issue cost recovery recorded under the retail rate order that or, if refinanced, over the life of the new issue which may range up to 50 years.

(c) Assessments for the decontamination and decommissioning of the DOE's nuclear fuel enrichment facilities are recorded annually from 1993 through 2008.

(d) Recorded as earned by employees and recovered as paid, generally within one year.

(e) Amortized over a three-year period ending in 2004. See Note 3 under "Retail Rate Orders".

(f) Recorded and recovered or amortized as approved by the GPSC.

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

All regulatory assets and liabilities are to be reflected in rates.

31

NOTES (continued)

Georgia Power Company 2003 Annual Report Depreciation and Amortization associated with the ultimate cost of retiring long-lived assets. The present value of the ultimate costs for an Depreciation of the original cost of plant in service is asset's future retirement must be recorded in the period provided primarily by using composite straight-line in which the liability is incurred. The costs must be rates, which approximated 2.7 percent in 2003, 2.9 capitalized as part of the related long-lived asset and percent in 2002 and 3.3 percent in 2001. The depreciated over the asset's useful life. Additionally, composite depreciation rate was reduced because the Statement No. 143 does not permit the continued lives of depreciable assets were extended effective accrual of future retirement costs for long-lived assets January 2002 under the retail rate order. When that the Company does not have a legal obligation to property subject to depreciation is retired or otherwise retire. However, the Company has received guidance disposed of in the normal course of business, its regarding accounting for the financial statement original cost -- together with the cost of removal, less impacts of Statement No. 143 from the GPSC and will salvage -- is charged to accumulated depreciation. continue to recognize the accumulated removal costs Minor items of property included in the original cost of for other obligations as a regulatory liability.

the plant are retired when the related property unit is Therefore, the Company had no cumulative effect to net retired. income resulting from the adoption of Statement No.

143.

The Company recorded accelerated depreciation and amortization amounting to $91 million in 2001. The liability recognized to retire long-lived assets Effective January 2002, the Company discontinued primarily relates to the Company's nuclear facilities, recording accelerated depreciation and amortization in which include the Company's ownership interests in accordance with a new retail rate order. Also, the plants Hatch and Vogtle. The fair value of assets legally Company was ordered to amortize $333 million -- the restricted for settling retirement obligations related to cumulative balance previously expensed - equally over nuclear facilities as of December 31, 2003 was S423 three years as a credit to amortization expense million. In addition, the Company has retirement beginning January 2002. Additionally, effective obligations related to various landfill sites, ash ponds, January 2002 the Company was ordered to recognize and underground storage tanks. The Company has also new GPSC certified purchased power costs in rates identified retirement obligations related to certain evenly over the three years covered by the current retail transmission and distribution facilities, leasehold rate order. As a result of the purchased power improvements, equipment on customer property, and regulatory adjustment, the Company recorded property associated with the Company's rail lines.

amortization expenses of $14 million and $63 million in However, a liability for the removal of these facilities 2003 and 2002, respectively. The Company will record will not be recorded because no reasonable estimate can a credit to amortization expense of $77 million in 2004. be made regarding the timing of any related retirements.

See Note 3 under "Retail Rate Orders" for additional The Company will continue to recognize in the information. Statements of Income the ultimate removal costs in accordance with its regulatory treatment. Any difference Asset Retirement Obligations between costs recognized under Statement No. 143 and and Other Costs of Removal those reflected in rates will be recognized as either a regulatory asset or liability in the Balance Sheets. The In accordance with regulatory requirements, prior to Company also revised the estimated cost to retire plants January 2003, the Company followed the industry Hatch and Vogtle as a result of a new site-specific practice of accruing for the ultimate cost of retiring decommissioning study. The effect of the revision is a most long-lived assets over the life of the related asset decrease of $24 million for the Statement No. 143 as part of the annual depreciation expense provision. In liability included in "Asset Retirement Obligations" with accordance with SEC requirements such amounts are a corresponding decrease in property, plant and reflected on the Balance Sheet as regulatory liabilities. equipment. See "Nuclear Decommissioning" for further Effective January 1, 2003, the Company adopted FASB information on amounts included in rates.

Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 established new accounting and reporting standards for legal obligations 32

NOTES (continued)

Georgia Power Company 2003 Annual Report Details of the asset retirement obligations included study as of December 31, 2003 and the Company's in the Balance Sheets are as follows: ownership interests in plants Hatch and Vogtle were as follows:

2003 (in millions) Plant Plant Balance beginning of year $469 Hatch Vootle Liabilities incurred Site study year 2003 2003 Liabilities settled Decommissioning periods:

Accretion 31 Beginning year 2034 2027 Cash flow revisions (24) Completion year . 2065 2048 Balance end of year $476 (in rrillions)

Site study costs:

If Statement No. 143 had been adopted on January 1, Radiated structures $497 $452 2002, the pro-forma asset retirement obligations would Non-radiated structures 49 58 have been $440 million. Total $546 $510 Nuclear Decommissioning The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from The Nuclear Regulatory Commission (NRC) requires service. The actual decommissioning costs may vary all licensees operating commercial nuclear power from the above estimates because of changes in the reactors to establish a plan for providing, with assumed date of decommissioning, changes in NRC reasonable assurance, funds for decommissioning. The requirements, or changes in the assumptions used in Company has established external trust funds to comply making the estimates.

with the NRC's regulations. The funds set aside for decommissioning are managed and invested in Annual provisions for nuclear decommissioning are accordance with applicable requirements of various based on an annuity method as approved by the GPSC.

regulatory bodies, including the NRC, the FERC and The amounts expensed in 2003 and fund balances were the GPSC as well as the Internal Revenue Service as follows:

(IRS). Funds are invested in a tax efficient manner in a diversified mix of equity and fixed income securities. Plant Plant Equity securities typically range from 50 to 75 percent Hatch Vogtle of the funds and fixed income securities from 25 to 50 (in millions) percent. Amounts previously recorded in internal Amount expensed in 2003 $ 7 $ 2 reserves are being transferred into the external trust Accumulated provisions:

funds over periods approved by the GPSC. The NRC's External trust funds, at fair $269 $154 minimum external funding requirements are based on a value generic estimate of the cost to decommission the Internal reserves 7 4 radioactive portions of a nuclear unit based on the size Total $276 $158 and type of reactor. The Company has filed plans with the NRC to ensure that - over time - the deposits and Effective January 1, 2002, the GPSC decreased the earnings of the external trust funds will provide the annual decommissioning costs for ratemaking to $9 minimum funding amounts prescribed by the NRC. million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the Site study cost is the estimate to decommission a facilities as of 2000. The estimates are $383 million and specific facility as of the site study year. The estimated

$282 million for plants Hatch and Vogtle, respectively.

costs of decommissioning are based on the most current Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 4.7 percent and an estimated trust earnings rate of 6.5 percent. The Company expects the GPSC to periodically review and adjust, if necessary, the amounts 33

NOTES (continued)

Georgia Power Company 2003 Annual Report collected in rates for the anticipated cost of next refueling. The refueling cycles range from 18 to 24 decommissioning. months for each unit. In accordance with the 2001 retail rate order, the Company defers the costs of certain In January 2002, the NRC granted the Company a significant inspection costs for the combustion turbines 20-year extension of the licenses for both units at Plant at Plant McIntosh and amortizes such costs over 10 Hatch which permits the operation of units I and 2 until years, which approximates the expected maintenance 2034 and 2038, respectively. The site study cycle.

decommissioning costs reflect the license extension; however, the updated costs will not be reflected in rates Impairment of Long-Lived Assets and Intangibles until the GPSC issues a new rate order, which is not expected until December 2004. 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 that exceeds the carrying and equity costs of capital funds that are necessary to value of the assets. If an impairment has occurred, the finance the construction of new regulated facilities. amount of the impairment recognized is determined by While cash is not realized currently from such allowance, either the amount of regulatory disallowance or by it increases the revenue requirement over the service life estimating the fair value of the assets and recording a of the plant through a higher rate base and higher loss if the carrying value is greater than the fair value.

depreciation expense. Interest related to the construction For assets identified as held for sale, the carrying value is of new facilities not included in the Company's retail compared to the estimated fair value less the cost to sell rates is capitalized in accordance with standard interest in order to determine if an impairment loss is required.

capitalization requirements. All current construction Until the assets are disposed of, their estimated fair value costs should be included in retail rates. For the years is re-evaluated when circumstances or events change.

2003, 2002, and 2001, the average AFUDC rates were 5.51 percent, 3.79 percent, and 6.33 percent, respectively. Cash and Cash Equivalents AFUDC and interest capitalized, net of taxes, was less than 3.0 percent of net income after dividends on For purposes of the financial statements, temporary cash preferred stock for 2003, 2002, and 2001. investments are considered cash equivalents. Temporary cash investments are securities with original maturities Property, Plant, and Equipment of 90 days or less.

Property, plant, and equipment is stated at original cost, Materials and Supplies less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; Generally, materials and supplies include the average appropriate administrative and general costs; cost of transmission, distribution, and generating plant payroll-related costs such as taxes, pensions, and other materials. Materials are charged to inventory when benefits; and the interest capitalized and/or cost of funds purchased and then expensed or capitalized to plant, as used during construction. appropriate, when installed.

The cost of replacements of property -- exclusive of Stock Options minor items of property -- is capitalized. The cost of Southern Company provides non-qualified stock options maintenance, repairs, and replacement of minor items of to a large segment of the Company's employees ranging property is charged to maintenance expense as incurred from line management to executives. The Company or performed with the exception of certain generating accounts for its stock-based compensation plans in plant maintenance costs. In accordance with a GPSC accordance with Accounting Principles Board Opinion order, the Company defers and amortizes nuclear No. 25. Accordingly, no compensation expense has refueling costs over the unit's operating cycle before the 34

NOTES (continued)

Georgia Power Company 2003 Annual Report been recognized because the exercise price of all options The Company's financial instruments for which the granted equaled the fair market value on the date of carrying amounts did not equal fair value at December grant. When options are exercised, the Company 31 were as follows:

receives a capital contribution from Southern Company

• equivalent to the related income tax benefit. Carrying Fair Amount Value Financial Instruments Long-term debt: (in millions)

At December 31, 2003 $3,685 $3,739 The Company uses derivative financial instruments to At December 31, 2002 $3,350 $3,417 limit exposures to fluctuations in interest rates, the prices Preferred securities:

of certain fuel purchases and electricity purchases and At December 31, 2003 $940 $976 sales. All derivative financial instruments are At December 31. 2002 $940 $961 recognized as either assets or liabilities and are measured at fair value. The fair values for securities were based on either closing market prices or closing prices of comparable The Company and its affiliates, through SCS acting instruments.

as their agent, enter into commodity related forward and option contracts to limit exposure to changing prices on Comprehensive Income certain fuel purchases and electricity purchases and sales. Substantially all of the Company's bulk energy The objective of comprehensive income is to report a purchases and sales contracts that meet the definition of measure of all changes in common stock equity of an a derivative are exempt from fair value accounting enterprise that result from transactions and other requirements and are accounted for under the accrual economic events of the period other than transactions method. Other derivative contracts qualify as cash flow with owners. Comprehensive income consists of net hedges of anticipated transactions. This results in the income, changes in the fair values of marketable deferral of related gains and losses in other securities and qualifying cash flow hedges, and changes comprehensive income or regulatory assets or liabilities in additional minimum pension liabilities, net of income as appropriate until the hedged transactions occur. Any taxes less reclassifications for amounts included in net ineffectiveness is recognized currently in net income. income.

Other derivative contracts are marked to market through current period income and are recorded on a net basis in 2. RETIREMENT BENEFITS the Statements of Income.

The Company has a defined benefit, trusteed pension The Company is exposed to losses related to plan covering substantially all employees. The plan is financial instruments in the event of counterparties' funded in accordance with Employee Retirement Income nonperformance. The Company has established Security Act (ERISA) requirements. No contributions to controls to determine and monitor the the plan are expected for the year ending December 31, creditworthiness of counterparties in order to mitigate 2004. The Company also provides certain non-qualified the Company's exposure to counterparty credit risk. benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds related trusts to the extent required by the GPSC and the FERC. For the year ended December 31, 2004, such contributions are expected to total approximately $8.9 million.

The measurement date for plan assets and obligations is September 30 for each year. In 2002, the Company adopted several plan changes that had the 35

NOTES (continued)

Ceorgia Power Company 2003 Annual Report effect of increasing benefits to both current and future minimizes the risk of large losses through diversification retirees. but also monitors and manages other aspects of risk.

Pension Plans Plan Assets Target 2003 2002 The accumulated benefit obligation for the pension plan Domestic equity 37% 37% 35%

was $1.6 billion and $1.4 billion for 2003 and 2002, International equity 20 20 18 respectively. Changes during the year in the projected Global fixed income 26 24 25 benefit obligations and in the fair value of plan assets Real estate 10 11 12 were as follows: Private equity 7 8 10 Total 100% 100% 100%

Projected Benefit Obligation The accrued pension costs recognized in the Balance 2003 2002 Sheets were as follows:

(in millions)

Balance at beginning of year $1,564 $1,448 2003 2002 Service cost 38 36 (in millions)

Interest cost 100 107 Funded status $328 $274 Benefits paid (83) (74) Unrecognized transition amount (13) (17)

Amendments 6 33 Unrecognized prior service cost 118 123 Actuarial loss 102 14 Unrecognized net actuarial gain Balance at end of year $1,727 S 1,564 (loss) (66) (78)

Prepaid pension asset, net 367 302 Portion included in employee Plan Assets benefit obligations 38 40 2003 2002 Total prepaid pension recognized in (in millions) the Balance Sheets $405 $342 Balance at beginning of year $1,838 $2,044 Actual return on plan assets 294 (137) In 2003 and 2002, amounts recognized in the Benefits paid (77) (69) Balance Sheets for accumulated other comprehensive Balance at end of year $2,055 $1,838 income and intangible assets to record the minimum pension liability related to the nonqualified plans were Pension plan assets are managed and invested in $26 million and $15 million and $13 and $10 million, accordance with all applicable requirements including respectively.

ERISA and the IRS 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 2003 2002 2001 tools but may also be used to gain efficient exposure to (in millions) the various asset classes. The Company primarily Service cost $ 38 $ 36 $ 35 Interest cost 100 107 101 Expected return on plan assets (179) (179) (168)

Recognized net gain (19) (27) (31)

Net amortization 6 4 3 Net pension (income) $ (54) $ (59) $ (60) 36

NOTES (continued)

Georgia Power Company 2003 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 2003 2002 follows: (in mnillions)

Funded status $(458) $(427)

Accumulated Unrecognized transition obligation 87 96 Benefit Obligation Unrecognized prior service cost 91 98 2003 2002 Unrecognized net loss 171 106 (in millions) Fourth quarter contributions 9 37 Balance at beginning of year $627 $542 Employee benefit obligations Service cost 9 8 recognized in the Balance Sheets $(100) $(90)

Interest cost 40 40 Benefits paid (29) (27) Components of the plans' net periodic cost were as Actuarial loss 76 64 follows:

Balance at end of year $723 $627 2003 2002 2001 Plan Assets (in millions) 2003 2002 Service cost $ 9 $ 8 $ 9 (in millions) Interest cost 40 40 39 Balance at beginning of year $199 $195 Expected return on Actual return on plan assets 36 (18) plan assets (24) (20) (19)

Employer contributions 59 49 Net amortization 16 15 14 Benefits paid (29) (27) Net postretirement cost $ 41 $ 43 $ 43 Balance at end of year $265 $199 The weighted average rates assumed in the actuarial Postretirement benefits plan assets are managed and calculations used to determine both the benefit invested in accordance with all applicable requirements, obligations and net periodic costs for the pension and including ERISA and the IRS revenue code. The postretirement benefit plans were:

Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, 2003 2002 2001 real estate, and private equity, as described in the table Discount 6.0% 6.5% 7.5%

below. Derivative instruments are used primarily as Annual salary increase 3.8 4.0 5.0 hedging tools but may also be used to gain efficient Long-term return on plan exposure to the various asset classes. The Company assets 8.5 8.5 8.5

• minimizes the risk of large losses through the primary tool of diversification but also monitors and manages The Company determined the long-term rate of other aspects of risk. return based on historical asset class returns and current market conditions, taking into account the diversification Plan Assets benefits of investing in multiple asset classes.

Target 2003 2002 Domestic equity 43% 42% 38% An additional assumption used in measuring the International equity 20 21 21 accumulated postretirement benefit obligations was a Global fixed income 33 32 35 weighted average medical care cost trend rate of 8.25 L Real estate 2 3 3 percent for 2003, decreasing gradually to 5.25 percent Private equity 2 2 3 through the year 2010 and remaining at that level Total 100% 100% 100% thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service 37

NOTES (continued)

Gcorgia Power Company 2003 Annual Report and interest cost components at December 31, 2003 as applied to rate refunds, with the remaining one-third follows: retained by the Company. The Company's earnings in 2003 and 2002 were within the common equity range.

I Percent I Percent Increase Decrease Under a previous three-year order ending December (in millions) 2001, the Company's earnings were evaluated against a Benefit obligation $70 $61 retail return on common equity range of 10 percent to Service and interest costs 5 4 12.5 percent. The order further provided for $85 million in each year, plus up to $50 million of any earnings Employee Savings Plan above the 12.5 percent return during the second and third years, to be applied to accelerated amortization or The Company sponsors a 401 (k) defined contribution depreciation of assets. Two-thirds of any additional plan covering substantially all employees. The earnings above the 12.5 percent return were applied to Company provides a 75 percent matching contribution rate refunds, with the remaining one-third retained by the up to 6 percent of an employee's base salary. Total Company. Pursuant to the order, the Company recorded matching contributions made to the plan for the years $333 million of accelerated amortization and interest 2003,2002, and 2001 were $18 million, $17 million, and thereon, which has been credited to a regulatory liability

$16 million, respectively. account as mandated by the GPSC.

3. CONTINGENCIES AND REGULATORY Under the 2001 rate order, the Company MATTERS discontinued recording accelerated depreciation and amortization and began amortizing the accumulated General Litigation Matters balance equally over three years as a credit to expense beginning in 2002. Also, the rate order required the The Company is subject to certain claims and legal Company to recognize capacity and operating and actions arising in the ordinary course of business. In maintenance costs related to new GPSC certified addition, the Company's business activities are subject purchased power contracts evenly in rates over a three -

to extensive governmental regulation related to public year period ending December 31, 2004.

health and the environment. Litigation over environmental issues and claims of various types, The Company is required to file a general rate case including property damage, personal injury, and citizen on July 1, 2004, in response to which the GPSC would enforcement of environmental requirements, has be expected to determine whether the rate order should increased generally throughout the United States. In be continued, modified, or discontinued.

particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become Under GPSC ratemaking provisions, $21 million has more frequent. The ultimate outcome of such litigation been deferred in a regulatory liability account for use in against the Company cannot be predicted at this time; meeting future environmental remediation costs.

however, management does not anticipate that the liabilities, if any, arising from such current proceedings Retail Fuel Hedging Program would have a material adverse effect on the Company's financial statements. On December 24, 2002, the GPSC approved an order, effective in January 2003, allowing the Company to Retail Rate Orders implement a natural gas and oil procurement and hedging program. This order allows the Company to use In December 2001, the GPSC approved a three-year financial instruments to hedge price and commodity risk retail rate order for the Company ending December 31, associated with these fuels. The order limits the 2004. Retail rates were decreased by $118 million program in terms of time, volume, dollars, and physical effective January 1, 2002. Under the terms of the order, amounts hedged. The costs of the program, including earnings are evaluated against a retail return on common any net losses, are recovered ais a fuel cost through the equity range of 10 percent to 12.95 percent. Two-thirds fuel cost recovery clause. Annual net financial gains of any earnings above the 12.95 percent return are from the hedging program will be shared with the retail 38

NOTES (continued)

Georgia Power Company 2003 Annual Report customers receiving 75 percent and the Company Company's transmission customers in October 2003 and retaining 25 percent of the net gains. $7.2 million was recorded as revenue.

Fuel Cost Recovery New Source Review Actions In May 2003, the Company filed for a fuel cost recovery In November 1999, the Environmental Protection rate increase. On August 19, 2003, the GPSC issued an Agency (EPA) brought a civil action against the order approving a stipulation reached by the Company, Company alleging the Company had violated the New the Consumers' Utility Counsel Division, Georgia Source Review (NSR) provisions of the Clean Air Act Textile Manufacturers Association, Georgia Industrial with respect to coal-fired generating facilities at the Group and the staff of the GPSC. The stipulation allows Company's Bowen and Scherer plants and violations of the Company to increase fuel rates to recover existing related state laws. The civil action requests penalties under-recovered deferred fuel costs over the period of and injunctive relief, including an order requiring the October 1, 2003 through March 31, 2005, as well as installation of the best available control technology at future projected fuel costs. The new fuel rate represents the affected units. The EPA concurrently issued to the an average annual increase in rates paid by customers of Company a notice of violation related to the two plants

• approximately 1.6 percent. mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations Nuclear Performance Standards alleged in its notice of violation.

The GPSC has adopted a nuclear performance standard The action against the Company was stayed in the for the Company's nuclear generating units under which spring of 2001 during the appeal of a very similar NSR the performance of plants Hatch and Vogtle is evaluated enforcement action against the Tennessee Valley every three years. The performance standard is based on Authority (TVA) before the U.S. Court of Appeals for each unit's capacity factor as compared to the average of the Eleventh Circuit. The TVA appeal involves many of all comparable U.S. nuclear units operating at a capacity the same legal issues raised by the actions against the factor of 50 percent or higher during the three-year Company. Because the final resolution of the TVA period of evaluation. Depending on the performance of appeal could have a significant impact on the Company, the units, the Company could receive a monetary award the Company has been involved in that appeal. On June or penalty under the performance standards criteria. 24, 2003, the court of appeals issued its ruling in the TVA case. It found unconstitutional the statutory For the period 1999-2001, the Company's scheme set forth in the Clean Air Act that allowed the performance fell within the criteria prescribed by the EPA to impose penalties for failing to comply with an GPSC. The Company will therefore not receive an administrative compliance order, like the one issued to award or penalty for the 1999-2001 performance TVA, without the EPA having to prove the underlying periods. violation. Thus, the court of appeals held that the compliance order was of no legal consequence, and TVA Open Access Transmission Tariff was free to ignore it. The court did not, however, rule directly on the substantive legal issues about the proper In October 2003, the FERC approved a new Open interpretation and application of certain NSR provisions Access Transmission Tariff for the Company of $1.73 that had been raised in the TVA appeal. On September per kilowatt-month based on an 11.25 percent return on 16, 2003, the court of appeals denied the EPA's request equity. The Company had requested a rate increase for a rehearing of the decision and on February 13, 2004, effective January 2002 based on a 13 percent return on the EPA petitioned the U.S. Supreme Court to review equity. Pending FERC approval, the Company collected the Eleventh Circuit's decision. At this time, no party to from customers based on the 13 percent return on equity, the Company's action, which was administratively but recorded revenue subject to refund for amounts closed two years ago, has asked the court to reopen that above the previously approved rate of $1.37 per case.

kilowatt-month. As a result of the final settlement, a total of approximately $2.3 million was refunded to the Since the inception of the NSR proceedings against the Company, the EPA has also been proceeding with 39

NOTES (continued)

Georgia Power Company 2003 Annual Report similar NSR enforcement actions against other utilities, supplemental environmental project, and attorneys' fees.

involving many of the same legal issues. In each case, The Clean Air Act authorizes civil penalties of up to the EPA alleged that the utilities failed to comply with $27,500 per day, per violation at each generating unit.

the NSR permitting requirements when performing maintenance and construction activities at coal-burning On June 19, 2003, the court granted the Company plants, which activities the Company considers to be motion to dismiss the allegations regarding hazardous air routine or otherwise not subject to NSR. In 2003, pollutants and denied the Company's motion to dismiss district courts addressing these cases issued opinions that the allegations regarding emission offsets. On August reached conflicting conclusions. 29, 2003, the Company filed a motion for partial summary judgment regarding emission offsets. On In October 2003, the EPA issued final revisions to January 20, 2004, the Company filed a motion for its NSR regulations under the Clean Air Act clarifying summary judgment on the remaining three counts, and the scope of the existing Routine Maintenance, Repair, the plaintiffs have filed motions for partial summary and Replacement exclusion. On December 24, 2003, the judgment. The case is currently scheduled for trial U.S. Court of Appeals for the District of Columbia during the summer of 2004. While the Company Circuit stayed the effectiveness of these revisions believes that it has complied with applicable laws and pending resolution of related litigation. In January 2004, regulations, an adverse outcome could require payment the Bush Administration announced that it would of substantial penalties. The final outcome of this matter continue to enforce the existing rules. cannot now be determined.

The Company believes that it complied with Potentially Responsible Party Status applicable laws and the EPA's regulations and interpretations in effect at the time the work in question The Company has been designated as a potentially took place. The Clean Air Act authorizes civil penalties responsible party at sites governed by the Georgia of up to $27,500 per day, per violation at each Hazardous Site Response Act and/or by the federal generating unit. Prior to January 30, 1997, the penalty Comprehensive Environmental Response, Compensation was $25,000 per day. An adverse outcome in this case and Liability Act. The Company has recognized $34 could require substantial capital expenditures that cannot million in cumulative expenses through December 31, be determined at this time and could possibly require 2003 for the assessment and anticipated cleanup of sites payment of substantial penalties. This could affect on the Georgia Hazardous Sites Inventory. In addition, future results of operations, cash flows, and financial in 1995 the EPA designated the Company and four other condition if such costs are not recovered through unrelated entities as potentially responsible parties at a regulated rates. site in Brunswick, Georgia that is listed on the federal National Priorities List. The Company has contributed Plant Wansley Environmental Litigation to the removal and remedial investigation and feasibility study costs for the site. Additional claims for recovery On December 30, 2002, the Sierra Club, Physicians for of natural resource damages at the site are anticipated.

Social Responsibility, Georgia ForestWatch, and one As of December 31, 2003, the Company had recorded individual filed a civil suit in the U.S. District Court in approximately $6 million in cumulative expenses Georgia against tile Company for alleged violations of associated with the Company's agreed-upon share of the the Clean Air Act at four of the generating units at Plant removal and remedial investigation and feasibility study Wansley. The complaint alleges Clean Air Act costs for the Brunswick site.

violations at both the existing coal-fired units and the new combined cycle units. Specifically, the plaintiffs The final outcome of these matters cannot now be allege (1) opacity violations at the coal-fired units, (2) determined. However, based on the currently known violations of a permit provision that requires the conditions at these sites and the nature and extent of the combined cycle units to operate above certain levels, (3) Company's activities relating to these sites, management violation of the nitrogen oxide emission offset does not believe that the Company's additional liability, requirements, and (4) violation of the hazardous air if any, at these sites would be material to the financial pollutant requirements. The civil action requests statements.

injunctive and declaratory relief, civil penalties, a 40

NOTES (continued)

Georgia Power Company 2003 Annual Report Race Discrimination Litigation plaintiffs' properties and that such actions by defendants exceed the easements or other property rights held by In July 2000, a lawsuit alleging race discrimination was defendants. The plaintiffs assert claims for, among other filed by three Georgia Power employees against the things, trespass and unjust enrichment. The plaintiffs Company, Southern Company, and SCS in the Superior seek compensatory and punitive damages and injunctive Court of Fulton County, Georgia. Shortly, thereafter, the relief. Management believes that the Company has lawsuit was removed to the U.S. District Court for the complied with applicable laws and the plaintiffs' claims Northern District of Georgia. The lawsuit also raised are without merit. An adverse outcome in these matters claims on behalf of a purported class. The plaintiffs could result in substantial judgments; however, the final seek compensatory and punitive damages in an outcome of these matters cannot now be determined.

unspecified amount, as well as injunctive relief. In August 2000, the lawsuit was amended to add four more In addition, in late 2001, certain subsidiaries of plaintiffs. Also, Southern Company Energy Solutions, a Southern Company, including Alabama Power, the subsidiary of Southern Company, was named a Company, Gulf Power, Mississippi Power, Savannah defendant. Electric and Southern Telecom (collectively, defendants) were named as defendants in a lawsuit brought by a In October 2001, the district court denied the telecommunications company that uses certain of the plaintiffs' motion for class certification. The plaintiffs defendants' rights of way. This lawsuit alleges, among filed a motion to reconsider the order denying class other things, that the defendants are contractually certification, and the court denied the plaintiffs' motion obligated to indemnify, defend, and hold harmless the to reconsider. In December 2001, the plaintiffs filed a telecommunications company from any liability that

• petition in the U. S. Court of Appeals for the Eleventh may be assessed against the telecommunications Circuit seeking permission to file an appeal of the company in pending and future right of way litigation.

October 2001 decision, and this petition was denied. The Company believes that the plaintiff's claims are After discovery was completed on the claims raised by without merit. An adverse outcome in this matter, the seven named plaintiffs, the defendants filed motions combined with an adverse outcome against the for summary judgment on all of the named plantiffs' telecommunications company in one or more of the right claims. On March 31, 2003, the U.S. District Court for of way lawsuits, could result in substantial judgments; the Northern District of Georgia granted summary however, the final outcome of these matters cannot now judgment in favor of the defendants on all claims raised be determined.

by all seven plaintiffs. On April 23, 2003 plaintiffs filed an appeal to the U.S. Court of Appeals for the Eleventh FERC Matters Circuit challenging these adverse summary judgment rulings, as well as the District Court's October 2001 The Company has obtained FERC approval to sell power ruling denying class certification. Oral arguments to non-affiliates at market-based prices under specific occurred January 27, 2004, and the parties await the contracts. The Company also has FERC authority to court's decision. The final outcome of this matter make short-term opportunity sales at market rates.

cannot now be determined. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In Right of Way Litigation November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based Southern Company and certain of its subsidiaries rates and adopted a new test called the Supply Margin including the Company, Gulf Power, Mississippi Power, Assessment (SMA). The FERC applied the SMA to and Southern Telecom (collectively defendants) have several utilities, including Southern Company's retail been named as defendants in numerous lawsuits brought operating companies, and found them to be "pivotal by landowners since 2001 regarding the installation and suppliers" in their control area market and ordered the use of fiber optic cable over defendants' rights of way implementation of certain mitigation measures. SCS, on located on the landowners' property. The plaintiffs' behalf of the Company and the other retail operating lawsuits claim that defendants may not use or sublease companies, sought rehearing of the FERC order and the to third parties some or all of the fiber optic FERC delayed implementation of certain mitigation communications lines on the rights of way that cross the measures. SCS, on behalf of the Company and the other 41

NOTES (continued)

Georgia Power Company 2003 Annual Report retail operating companies, submitted comments to the electric generating units with a total rated capacity of FERC in 2002 regarding these issues. In December 1,020 megawatts, as well as associated transmission 2003, the FERC issued a staff paper discussing facilities. The capacity of the units has been sold alternatives and held a technical conference in January equally to the Company and Alabama Power under a 2004. The Company anticipates that the FERC will contract which, in substance, requires payments address the requests for rehearing in the near future. sufficient to provide for the operating expenses, taxes, Regardless of the outcome of the SMA proposal, the debt service, and return on investment, whether or not FERC retains the ability to modify or withdraw the SEGCO has any capacity and energy available. The authorization for any seller to sell at market-based rates, term of the contract extends automatically for two-year if it determines that the underlying conditions for having periods, subject to either party's right to cancel upon two such authority are no longer applicable. The final year's notice. The Company's share of expenses outcome of this matter will depend on the form in which included in purchased power from affiliates in the the SMA test and mitigation measures rules may be Statements of Income is as follows:

ultimately adopted and cannot be determined at this time. 2003 2002 2001 (in millions)

PPAs by the Company for Southern Power's Plant Energy $55 $53 $52 McIntosh capacity were certified by the GPSC in Capacity 34 32 30 December 2002 after a competitive bidding process. In Total $89 $85 $82 April 2003, Southern Power applied for FERC approval of these PPAs. Interveners have made filings in The Company owns undivided interests in plants opposition of the FERC's acceptance of the PPAs, Vogtle, Hatch, Scherer, and Wansley in varying amounts alleging that the PPAs do not meet the applicable jointly with Oglethorpe Power Corporation (OPC), the standards for market-based rates between affiliates. In Municipal Electric Authority of Georgia (MEAG), the July 2003, the FERC accepted the PPAs to become city of Dalton, Georgia, Florida Power & Light effective June 1, 2005, subject to refund, and ordered Company, Jacksonville Electric Authority, and Gulf that hearings be held to determine: (a) whether, in the Power. Under these agreements, the Company is jointly design and implementation of the GPSC competitive and severally liable for third party claims related to these bidding process, the Company unduly preferred plants. In addition, the Company jointly owns the Southern Power; (b) whether the analysis of the Rocky Mountain pumped storage hydroelectric plant competitive bids unduly favored Southern Power, with OPC who is the operator of the plant. The particularly with respect to evaluation of non-price Company also jointly owns Plant McIntosh with factors; (c) whether the Company selected its affiliate, Savannah Electric who operates the plant. The Southern Power, based upon a reasonable combination Company and Florida Power Corporation (FPC) jointly of price and non-price factors; (d) whether Southern own a combustion turbine unit (Intercession City)

Power received an undue preference or competitive operated by FPC.

advantage in the competitive bidding process as a result of access to its affiliate's transmission system; (e) whether and to what extent the PPAs impact wholesale competition; and (f) whether the PPAs are just and reasonable and not unduly discriminatory. Hearings are scheduled to begin in March 2004. Management believes that the PPAs should be approved by the FERC; however, the ultimate outcome of this matter cannot now be determined.

4. JOINT OWNERSHIP AGREEMENTS The Company and an affiliate, Alabama Power, own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which owns 42

NOTES (continued)

Georgia Power Company 2003 Annual Report At December 31, 2003, the Company's percentage at rates higher than' current enacted tax law and to ownership and investment (exclusive of nuclear fuel) in unamortized investment tax credits.

jointly owned facilities in commercial operation were as follows: Details of the federal and state income tax provisions are as follows:

Company Accumulated Facility (Type) Ownership Investment Depreciation 2003 2002 2001 (in millions)

Total provision for income taxes: (in millions)

Plant Vogtle (nuclear) 45.7% $3,307 $1,706 Federal:

Plant Hatch (nuclear) 50.1 908 469 Plant Wansley (coal) Current $ 143 $261 $352 53.5 390 160 Plant Scherer (coal) Deferred 181 60 (46)

Units I and 2 8.4 115 52 324 321 306 Unit 3 75.0 560 247 State:

Plant McIntosh Current 24 31 61 Common Facilities 75.0 24 3 Deferred 16 5 (8)

(combustion-turbine) Deferred investment tax Rocky Mountain 25.4 169 85 credits 2 - 5 (pumped storage) Total $366 $357 $364 Intercession City 33.3 12 1 (combustion-turbine)

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial The Company has contracted to operate and statements and their respective tax bases, which give rise maintain the jointly owned facilities as agent for their to deferred tax assets and liabilities, are as follows:

co-owners, except as noted above. The Company's proportionate share of its plant operating expenses is 2003 2002 included in the corresponding operating expenses in the (in millions)

Statements of Income. Deferred tax liabilities:

Accelerated depreciation $1,966 $1,779

5. INCOME TAXES Property basis differences 563 623 Other 329 309 Southern Company and its subsidiaries file a -

Total 2,858 2,711 consolidated federal income tax return. As a result of Deferred tax assets:

new State of Georgia Department of Revenue Federal effect of state deferred taxes 96 90 regulations applicable to tax years beginning on or after Other property basis differences 156 170 January 1, 2002, Southern Company and its subsidiaries Other deferred costs 160 214 were granted permission by the State of Georgia Other 75 64 Department of Revenue Commissioner to file a -

Total 487 538 combined State of Georgia income tax return. Under a Net deferred tax liabilities 2,371 2,173 joint consolidated income tax agreement, each Portion included in prepaid expenses 3 subsidiary's current and deferred tax expense is -

Accumulated deferred income taxes computed on a stand-alone basis. In accordance with in the Balance Sheets $2,371 $2,176 both IRS and State of Georgia Department of Revenue regulations, each company is jointly and severally liable for the tax liability. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the At December 31, 2003, tax-related regulatory assets related property with such amortization normally applied were $510 million and tax-related regulatory liabilities as a credit to reduce depreciation in the Statements of were $187 million. The assets are attributable to tax Income. Credits amortized in this manner amounted to benefits flowed through to customers in prior years and $15 million in 2003, $12 million in 2002 and $15 to taxes applicable to capitalized interest. The liabilities million in 2001. At December 31, 2003, all investment are attributable to deferred taxes previously recognized 43

NOTES (continued)

Georgia Power Company 2003 Annual Report tax credits available to reduce federal income taxes First Mortgage Bond Indenture payable had been utilized.

In 2002, the first mortgage bond indenture of the A reconciliation of the federal statutory tax rate to Company was defeased by paying to JPMorgan Chase the effective income tax rate is as follows: Bank, the trustee, an amount representing the last outstanding obligations on the Company's first mortgage 2003 2002 2001 bonds. As a result of the defeasance, there are no longer Federal statutory rate 35% 35% 35% any first mortgage bond liens on the Company's State income tax, net of property and the Company no longer has to comply with federal deduction 3 2 4 the covenants and restrictions of the first mortgage bond Non-deductible book indenture.

depreciation 1 2 Other (2) (I) (4) Pollution Control Bonds Effective income tax rate 37% 37% 37%

The Company has incurred obligations in connection

6. CAPITALIZATION with the sale by public authorities of tax-exempt pollution control revenue bonds. The amount of tax-Mandatorily Redeemable Preferred Securities exempt pollution control revenue bonds outstanding at December 31, 2003 was $1.7 billion.

The Company has formed certain wholly-owned trust subsidiaries for the purpose of issuing preferred Capital Leases securities. The proceeds of the related equity investments and security sales were loaned back to the Assets acquired under capital leases are recorded in the Company through the issuance of junior subordinated Balance Sheets as utility plant in service, and the related notes totaling $969 million, which constitute obligations are classified as long-term debt. At substantially all of the assets of the trusts. The Company December 31, 2003 and 2002, the Company had a considers that the mechanisms and obligations relating capitalized lease obligation for its corporate headquarters to the preferred securities issued for its benefit, taken building of $79 million and $81 million, respectively, together, constitute a full and unconditional guarantee by with an interest rate of 8.1 percent. For ratemaking it of the respective trusts' payment obligations with purposes, the GPSC has treated the lease as an operating respect to these preferred securities. At December 31, lease and has allowed only the lease payments in cost of 2003, preferred securities of $940 million were service. The difference between the accrued expense outstanding and recognized as liabilities in the Balance and the lease payments allowed for ratemaking purposes Sheets. has been deferred and is being amortized to expense as ordered by the GPSC. At both December 31, 2003 and Long-Term Debt Due Within One Year 2002, the interest and lease amortization deferred on the Balance Sheets was $54 million.

A summary of the improvement fund requirements and scheduled maturities and redemptions of securities due Bank Credit Arrangements within one year at December 31 is as follows:

At the beginning of 2004, the Company had an unused 2003 2002 credit arrangement with banks totaling $725 million (in millions) expiring at June 11, 2004. Upon expiration, the $725 Capital lease $2 $ 2 million agreement provides the option of converting Senior notes 320 borrowings into a two-year term loan. The agreement Total $2 $322 contains stated borrowing rates but also allows for competitive bid loans. In addition, the agreement Serial maturities through 2008 applicable to total requires payment of commitment fees based on the long-termn debt are as follows: $2 million in 2004; $453 unused portion of the commitments or the maintenance million in 2005; $153 million in 2006; $303 million in of compensating balances with the banks. Commitment 2007; and $3 million in 2008. fees are less than 1/8 of I percent for the Company.

44

NOTES (continued)

Georgia Power Company 2003 Annual Report Compensating balances are not legally restricted from At December 31, 2003, the fair value of derivative withdrawal. A fee is also paid to the 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, as defined in the agreement. Exceeding these limits Amounts would result in an event of default under the credit (in millions) arrangement. In addition, the credit arrangements Regulatory liabilities, net $3.2 contain cross default provisions that would trigger an Other comprehensive income event of default if the Company defaulted on other Net income indebtedness above a specified threshold. The Company Total fair value - $3.2 is currently in compliance with all such covenants.

The Company enters into derivatives to hedge This $725 million in unused credit arrangements exposure to interest rate changes. Derivatives related to provides liquidity support to the Company's variable variable rate securities or forecasted transactions are rate pollution control bonds. The amount of variable accounted for as cash flow hedges. The derivatives are rate pollution control bonds outstanding requiring generally structured to mirror the critical terms of the liquidity support as of December 31, 2003 was $106 hedged debt instruments; therefore, no material million. In addition, the Company borrows under a ineffectiveness has been recorded in earnings.

commercial paper program and an extendible commercial note program. The amount of commercial At December 31,2003, the Company had interest paper outstanding at December 31, 2003 was $137 rate swaps outstanding with net deferred losses as million. There were no outstanding extendible follows:

commercial notes at December 31, 2003. The amount of commercial paper outstanding at December 31, 2002 Cash Flow Hedges was $358 million, which included $19 million of extendible commercial notes. During 2003, the peak Weighted amount of commercial paper outstanding was $531 Average million and the average amount outstanding was $229 Fixed Fair million. The average annual interest rate on commercial Rate Notional Value paper in 2003 was 1.23 percent. Commercial paper is Maturity Paid Amount (Loss) included in notes payable on the Balance Sheets. (in millions) 2004 1.39% $873 $(0.8)

Financial Instruments 2005 1.56 50 0 2005 1.96 250 (1.1)

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price The fair value gain or loss for cash flow hedges is changes. However, due to cost-based rate regulations, recorded in other comprehensive income and is the Company has limited exposure to market volatility in reclassified into earnings at the same time the hedged commodity fuel prices and prices of electricity. The items affect earnings. In 2003, the Company recognized Company has implemented fuel-hedging programs at the losses totaling $11.3 million upon termination of certain instruction of the GPSC. The Company also enters into interest derivatives at the same time it issued debt.

hedges of forward electricity sales. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the related debt. For 2003, approximately

$3.4 million of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2004, pre-tax losses of approximately $3.2 million are expected to be reclassified from other comprehensive income to interest expense.

45

NOTES (continued)

Ceorgia Power Company 2003 Annual Report

7. COMMITMENTS Fuel and Purchased Power Commitments Construction Program To supply a portion of the fuel requirements of its generating plants, the Company has entered into various The Company currently estimates property additions to long-term commitments for the procurement of fossil be approximately $747 million, $812 million, and and nuclear fuel. In most cases, these contracts contain

$1,043 million in 2004, 2005, and 2006, respectively. provisions for price escalations, minimum purchase These amounts include $28.9 million, $19.7 million and levels, and other financial commitments. Natural gas

$20.0 million in 2004, 2005, and 2006, respectively, for purchase commitments contain fixed volumes with construction expenditures related to contractual purchase prices based on various indices at the time of delivery.

commitments for uranium and nuclear fuel conversion, Amounts included in the chart below represent estimates enrichment, and fabrication services included under based on New York Mercantile future prices at "Fuel and Purchased Power Commitments." The December 31, 2003. Also the Company has entered into construction program is subject to periodic review and various long-term commitments for the purchase of revision, and actual construction costs may vary from electricity. Total estimated minimum long-term estimates because of numerous factors, including, but obligations at December 31, 2003 were as follows:

not limited to, changes in business conditions, changes in FERC rules and transmission regulations, revised load Coal and growth estimates, changes in environmental regulations, Natural Nuclear changes in existing nuclear plants to meet new Year Gas Fuel regulatory requirements, increasing costs of labor, (in millions) equipment, and materials, and cost of capital. At 2004 $ 156 $1,321 December 31, 2003, significant purchase commitments 2005 149 1,045 were outstanding in connection with the construction 2006 148 895 program. 2007 108 603 2008 172 372 2009 and thereafter 1,625 183 The Company has no generating plants under -

Total commitments $2,358 $4.419 construction. However, construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission and Additional commitments for coal and for nuclear distribution facilities, including those needed to meet the fuel will be required to supply the Company's future environmental standards previously discussed, are needs.

ongoing.

SCS may enter into various types of wholesale The Company had three generation projects under energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company construction during 2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each turbine facility; two combined cycle units totaling 1,132 megawatts at Plant Wansley; and Plant Franklin, a two- of the retail operating companies, Southern Power, and Southern Company Gas may be jointly and severally unit, 1,181 megawatt combined cycle facility. All three of these projects have been transferred to Southern liable. The creditworthiness of Southern Power and Power. The ten Dahlberg units and two Franklin units Southern Company GAS is currently inferior to the were transferred in 2001 and the transfer of the two creditworthiness of the retail operating companies.

Accordingly, Southern Company has entered into keep-Wansley units was completed in January 2002.

well agreements with the Company and each of the retail Southern Company has guaranteed Southern Power operating companies to insure they will not subsidize or obligations totaling $10.7 million for the Company's be responsible for any costs, losses, liabilities, or construction of transmission interconnection facilities to damages resulting from the inclusion of Southern Power these plants. or Southern Company GAS as a contracting party under these agreements.

46

NOTES (continued)

Georgia Power Company 2003 Annual Report The Company has commitments regarding a portion million for 2003, $35 million for 2002, and $14 million of a 5 percent interest in Plant Vogtle owned by MEAG for 2001. At December 31, 2003, estimated minimum that are in effect until the latter of the retirement of the rental commitments for these noncancelable operating plant or the latest stated maturity date of MEAG's bonds leases were as follows:

issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is Minimum Obligations available. The energy cost is a function of each unit's Year Rail Cars Other Total variable operating costs. Except as noted below, the cost (in millions) of such capacity and energy is included in purchased 2004 $ 12 $22 $ 34 power from non-affiliates in the Company's Statements 2005 12 18 30 of Income. Capacity payments totaled $57 million, $57 2006 12 14 26 million, and $59 million in 2003, 2002, and 2001, 2007 10 12 22 respectively. The current projected Plant Vogtle 2008 11 11 22 capacity payments are: 2009 and thereafter 56 16 72 Year Capacity Payments Total $113 $93 $206 (in millions) 2004 $ 57 In addition to the rental commitments above, the 2005 56 Company has obligations upon expiration of certain rail 2006 54 car leases with respect to the residual value of the leased 2007 54 property. These leases expire in 2004 and 2010, and the 2008 54 Company's maximum obligations are $13 million and 2009 and thereafter 369 $40 million, respectively. At the termination of the Total $644 leases, at the Company's option, the Company may either exercise its purchase option or the property can be Portions of the payments noted above relate to costs sold to a third party. The Company expects that the fair in excess of Plant Vogde's allowed investment for market value of the leased property would substantially ratemaking purposes. The present value of these reduce or eliminate the Company's payments under the portions at the time of the disallowance was written off. residual value obligation. A portion of the rail car lease obligations is shared with the joint owners of plants The Company has entered into other various long- Scherer and Wansley. Rental expenses related to the rail term commitments for the purchase of electricity. car leases are fully recoverable through the fuel cost Estimated total long-term obligations at December 31, recovery clause as ordered by the GPSC.

2003 were as follows:

Guarantees Non-Year Affiliated Affiliated Prior to 1999, a subsidiary of Southern Company (in millions) originated loans to residential customersof the Company 2004 $ 191 $ 45 for heat pump purchases.' These loans were sold to 2005 268 79 Fannie Mae with recourse for any loan with payments 2006 283 88 outstanding over 120 days. The Company is responsible 2007 283 89 for the repurchase of customers' delinquent loans. As of 2008 282 90 December 31, 2003, the outstanding loans guaranteed by 2009 and thereafter 1,722 '482 the Company were $8.7 million and loan loss reserves of Total $3,029 $873 $1.8 million' have been recorded.

Operating Leases Alabama Power has guaranteed unconditionally the obligation of SEGCO urde'ran instalrhient sale I The Company has entered into various operating leases agreement for the purchase of certain pollution control with various terms and expiration dates. Rental facilities at SEGCO's generating units, pursuant to expenses related to these operating leases totaled $36 47

NOTES (continued)

Georgia Power Company 2003 Annual Report which $24.5 million principal amount of pollution Additionally, the Company has policies that control revenue bonds are outstanding. The Company currently provide decontamination, excess property has agreed to reimburse Alabama Power for the pro rata insurance, and premature decommissioning coverage up portion of such obligation corresponding to the to $2.25 billion for losses in excess of the $500 million Company's then proportionate ownership of stock of primary coverage. This excess insurance is also SEGCO if Alabama Power is called upon to make such provided by NEIL.

payment under its guaranty. In May 2003, SEGCO issued an additional $50 million in senior notes. NEIL also covers additional costs that would be Alabama Power guaranteed the debt obligation and in incurred in obtaining replacement power during a October 2003, the Company agreed to reimburse prolonged accidental outage at a member's nuclear plant.

Alabama Power for the pro rata portion of such Members can purchase this coverage, subject to a obligation corresponding to its then proportionate deductible waiting period of up to 26 weeks, with a ownership of stock of SEGCO if Alabama Power is maximum per occurrence per unit limit of $490 million.

called upon to make such payment under its guaranty. After this deductible period, weekly indemnity payments would be received until either the unit is operational or As discussed earlier in this note under "Operating until the limit is exhausted in approximately three years.

Leases," the Company has entered into certain residual The Company purchases the maximum limit allowed by value guarantees related to rail car leases. NEIL subject to ownership limitations and has elected a 12 week waiting period.

8. NUCLEAR INSURGNCE Under each of the NEIL policies, members are Under the Price-Anderson Amendments Act of 1988, the subject to assessments if losses each year exceed the Company maintains agreements of indemnity with the accumulated funds available to the insurer under that NRC that, together with private insurance, cover policy. The current maximum annual assessments for third-party liability arising from any nuclear incident the Company under the NEIL policies would be $40 occurring at the Company's nuclear power plants. The million.

Act provides funds up to $10.9 billion for public liability claims that could arise from a single nuclear incident. Following the terrorist attacks of September 2001, Each nuclear plant is insured against this liability to a both ANI and NEIL confirmed that terrorist acts against maximum of $300 million by American Nuclear Insurers commercial nuclear power stations would be covered (ANI), with the remaining coverage provided by a under their insurance. Both companies, however, mandatory program of deferred premiums that could be revised their policy terms on a prospective basis to assessed, after a nuclear incident, against all owners of include an industry aggregate for all "non-certified" nuclear reactors. The Company could be assessed up to terrorist acts (i.e., acts that are not certified acts of

$ 101 million per incident for each licensed reactor it terrorism pursuant to the Terrorism Risk Insurance Act operates but not more than an aggregate of $10 million of 2002 (TRIA). The NEIL aggregate -- applies to non-per incident to be paid in a calendar year for each certified claims stemming from terrorism within a 12-reactor. Such maximum assessment for the Company, month duration -- is $3.24 billion plus any amounts excluding any applicable state premium taxes -- based available through reinsurance or indemnity from an on its ownership and buyback interests -- is $203 million outside source. The non-certified ANI cap is a $300 per incident but not more than an aggregate of $20 million shared industry aggregate. Any act of terrorism million to be paid for each incident in any one year. The that is certified pursuant to the TRIA will not be subject Price-Anderson Amendments Act expired in August to the foregoing NEIL and ANI limitations but will be 2002; however, the indemnity provisions of the Act subject to the TRIA annual aggregate limitation of $100 remain in place for commercial nuclear reactors. billion of insured losses arising from certified acts of terrorism. The TRIA will expire on December 31, 2005.

The Company is a member of Nuclear Electric Insurance Limited (NEL), a mutual insurer established For all on-site property damage insurance policies to provide property damage insurance in an amount up for commercial nuclear power plants, the NRC requires to $500 million for members' nuclear generating that the proceeds of such policies shall be dedicated first facilities. for the sole purpose of placing the reactor in a safe and 48

NOTES (continued)

Georgia Power Company 2003 Annual Report 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.

9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2003 and 2002 is as follows:

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

March 2003 $1,126 $262 $133 June 2003 1,190 293 159 September 2003 1,487 490 265 December 2003 1,111 179 74 March 2002 $1,007 $260 $127 June 2002 1,204 320 171 September2002 1,517 498 271 December 2002 1,095 126 49 The Company's business is influenced by seasonal weather conditions.

49

SELECTED FINANCIAL AND OPERATING DATA 1999-2003 Georgia Power Company 2003 Annual Report 2003 2002 2001 2000 1999 Operating Revenues (in thousands) S4,913,507 $4,822,460 $4,965,794 $4,870,618 $4,456,675 Net Income after Dividends on Preferred Stock (in thousands) $630,577 $617,629 $610,335 $559,420 S541,383 Cash Dividends on Common Stock (in thousands) $565,800 $542,900 $527,300 $549,600 $543,000 Return on Average Common Equity (percent) 14.05 13.99 14.12 13.66 14.02 Total Assets (in thousands) $14,782,028 $14,342,656 $14,447,973 S 13,971,211 $13,148,049 Gross Property Additions (in thousands) $742,810 S883,968 $1,389,751 S1,078,163 $790,464 Capitalization (in thousands):

Common stock equity $4,540,211 $4,434,447 $4,397,485 $4,249,544 S3,938,210 Preferred stock 14,569 14,569 14,569 14,569 14,952 Mandatorily redeemable preferred securities 940,000 940,000 789,250 789,250 789,250 Long-tenm debt 3,762,333 3,109,619 2,961,726 3,041,939 2,688,358 Total (excluding amounts due within one year) $9,257,113 S8,498,635 $8,163,030 S8,095,302 S7,430,770 Capitalization Ratios (percent):

Common stock equity 49.0 52.2 53.9 52.5 53.0 Preferred stock 0.2 0.2 0.2 0.2 0.2 Mandatorily redeemable preferred securities 10.2 11.1 9.6 9.7 10.6 Long-termn debt 40.6 36.5 36.3 37.6 36.2 Total (excluding amounts due within one vear) 100.0 100.0 100.0 100.0 100.0 Security Ratings:

First Mortgage Bonds -

Moody's N/A N/A Al Al Al Standard and Poor's N/A N/A A A A+

Fitch N/A N/A AA- AA- AA-Preferred Stock -

Moody's Baal Baal Baal a2 a2 Standard and Poor's BBB+ BBB+ BBB+ BBB+ A-Fitch A A A A A+

Unsecured Long-Tenn 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 1,768,662 1,734,430 1,698,407 1,669,566 1,632,450 Commercial 258,276 250,993 244,674 237,977 229,524 Industrial 7,899 8,240 8,046 8,533 8,958 Other 3,434 3,328 3,239 3,159 3,060 Total 2,038,271 1,996,991 1,954,366 1,919,235 1,873,992 Employees (year-end): 8,714 8,837 9,048 8,860 8,961 N/A = Not Applicable.

50

SELECTED FINANCIAL AND OPERATING DATA 1999-2003 (continued)

Georgia Power Company 2003 Annual Report 2003 2002 2001 2000 1999 Operating Revenues (in thousands):

Residential S 1,583,082 $1,600,438 $ 1,507,031 $ 1,535,684 $ 1,410,099 Commercial 1,661,054 1,631,130 1,682,918 1,620,466 1,527,880 Industrial 1,012,267 1,004,288 1,106,420 1,154,789 1,143,001 Other 53,569 52,241 52,943 6,399 (30,892)

Total retail 4,309,972 4,288,097 4,349,312 4,317,338 4,050,088 Sales for resale - non-affiliates 259,376 270,678 366,085 297,643 210,104 Sales for resale - affiliates 174,855 98,323 99,411 96,150 76,426 Total revenues from sales of electricity 4,744,203 4,657,098 4,814,808 4,711,131 4,336,618 Other revenues 169,304 165,362 150,986 159,487 120,057 Total $4,913,507 $4.822,460 $4.965.794 $4.870.618 $4,456.675 Kilowatt-Hlour Sales (in thousands):

Residential 21,778,582 22,144,559 20,119,080 20,693,481 19,404,709 Commercial 26,940,572 26,954,922 26,493,255 25,628,402 23,715,485 Industrial 25,703,421 25,739,785 25,349,477 27,543,265 27,300,355 Other 595,742 593,202 583,007 568,906 551,451 Total retail 75,018,317 75,432,468 72,544,819 74,434,054 70,972,000 Sales for resale - non-affiliates 8,835,804 8,069,375 8,110,096 6,463,723 5,060,931 Sales for resale -affiliates 5,844,196 3,962,559 3,133,485 2,435,106 1,795,243 Total 89,698,317 87,464,402 83,788,400 83.332,883 77,828.174 Average Revenue Per Kilowatt-hlour (cents):

Residential 7.27 7.23 7.49 7.42 7.27 Commercial 6.17 6.05 6.35 6.32 6.44 Industrial 3.94 3.90 4.36 4.19 4.19 Total retail 5.75 5.68 6.00 5.80 5.71 Sales for resale 2.96 3.07 4.14 4.43 4.18 Total sales 5.29 5.32 5.75 5.65 5.57 Residential Average Annual Kilowatt-Hour Use Per Customer 12,421 12,867 11,933 12,520 12,006 Residential Average Annual Revenue Per Customer S902.70 $929.90 $893.84 $929.11 S872.48 Plant Nameplate Capacity Ratings (year-end) (megawatts) 13,980 14,059 14,474 15,114 14,474 Maximum Peak-Hour Demand (megawatts):

Winter 13,153 11,873 11,977 12,014 11,568 Summer 14,826 14,597 14,294 14,930 14,575 Annual Load Factor (percent) 61.0 60.4 61.7 61.6 58.9 Plant Availability (percent):

Fossil-steam 87.6 80.9 88.5 86.1 84.3 Nuclear 94.2 88.8 94.4 91.5 89.3 Source of Energy Supply (percent):

Coal 58.6 59.5 58.5 62.3 63.0 Nuclear 16.8 16.2 18.1 17.4 18.0 Hydro 2.1 0.9 1.1 0.7 0.9 Oil and gas 0.3 0.3 0.4 1.8 1.6 Purchased power -

From non-affiliates 7.5 6.3 7.8 8.1 6.6 From affiliates 14.7 16.8 14.1 9.7 9.9 Total 100.0 100.0 100.0 100.0 100.0 51

DIRECTORS AND OFFICERS Georgia Power Company 2003 Annual Report Directors Officers Juanita 1P.Baranco David Al. Ratcliffe Chief Operating Officer Chairman of the Board and Chief Baranco Automotive Group Executive Officer Robert L. Brown, Jr. Michael D. Garrett President and Chief Executive Officer President R. L. Brown & Associates, Inc.

Judy M1. Anderson Anna R. Cablik Senior Vice President Owner and President Charitable Giving Anatek, Inc. & Anasteel & Supply Co., LLC William C. Archer, III II. Allen Franklin Executive Vice President Chairman, President and Chief Executive Officer External Affairs Southern Company Ronnie L. Bates Michael D. Garrett Senior Vice President President Planning, Sales and Service Georgia Power Company M. A. Brown David M. Ratcliffe Senior Vice President Chairman of the Board and Chief Executive Officer Distribution Georgia Power Company C. B. (Mike) Ilarreld D. Gary Thompson Executive Vice President, Treasurer and Chief Chief Executive Officer Financial Officer Georgia Banking Wachovia Corporation Richard L. Holmes Richard W. Ussery Senior Vice President Chairman of the Board Corporate Services TSYS James II. Miller, IlI (effective 3/13/04)

William Jerry Vercen Senior Vice President and Chairman, President and Chief Executive Officer General Counsel Riverside Manufacturing Company Leslie R. Sibert Carl WVare Vice President Executive Vice President Transmission The Coca-Cola Company Chris C. WVomack E. Jenner Wood, III Senior Vice President Chairman, President and Chief Executive Officer Fossil and Hydro Power SunTrust Bank, Central Group 52

DIRECTORS AND OFFICERS Georgia Power Company 2003 Annual Report W. Craig Barrs Anne H. Kaiser Vice President Vice President Community and Economic Development Sales Rebecca A. Blalock Ellen N. Lindemann Vice President Vice President Information Resources Human Resources A. Bryan Fletcher Frank J. McCloskey Vice President Vice President Region Distribution Diversity and Corporate Relations J. Kevin Fletcher James E. Sykes, Jr.

Vice President Vice President Marketing and Customer Service Region Distribution

0. Ben Harris J. L. Wallace Vice President Vice President Land Planning and Pricing WV. Ron Hinson Janice G. Wolfe Vice President, Comptroller and Corporate Secretary and Chief Accounting Officer Assistant Comptroller Chris M. Hobson Wayne Boston Vice President Assistant Secretary and Environmental Affairs Assistant Treasurer Ed F. llolcombe Vice President Governmental and Regulatory Affairs E. Lamont Houston Vice President Region Distribution Brian L. (Pete) Ivey Vice President Administrative Services 53

CORPORATE INFORMATION Georgia Power Company 2003 Annual Report General Registrar, Transfer Agent, and Dividend This annual report is submitted for general Paying Agent information and is not intended for use in Preferred Stock connection with any sale or purchase of, or Southern Company Services, Inc.

any solicitation of offers to buy or sell, Stockholder Services securities. P.O. Box 54250 Atlanta, GA 30308-0250 Profile (800) 554-7626 The Company produces and delivers electricity as an integrated utility to both retail Form 10-K and wholesale customers within the State of A copy of Form 10-K as filed with the Georgia. The Company sells electricity to Securities and Exchange Commission will some 2.0 million customers within its service be provided upon written request to the area of approximately 57,000 square miles. In office of the Corporate Secretary. For 2003, retail energy sales accounted for additional information, contact the office of 84 percent of the Company's total sales of the Corporate Secretary at (404) 506-7450.

89.7 billion kilowatt-hours.

Georgia Power Company The Company is a wholly owned subsidiary of 241 Ralph McGill Boulevard, N.E.

Southern Company, which is the parent Atlanta, GA 30308-3374 company of five regulated Southeast utilities. (404) 506-6526 There is no established public trading market www.georgiapower.com for the Company's common stock.

Auditors Audit Committee Deloitte & Touche LLP In 2003, the board of directors amended the Suite 1500 Company's bylaws to remove the provision 191 Peachtree Street, N.E.

requiring an Audit Committee and to create a Atlanta, GA 30303 Controls and Compliance Committee. The Southern Company Audit Committee provides Legal Counsel broad oversight of the Company's financial Troutman Sanders LLP reporting and control functions. 600 Peachtree Street, N.E.

Suite 5200 Trustee, Registrar, and Interest Paying Agent Atlanta, GA 30308 All series of Senior Notes and Preferred Securities JPMorgan Chase Bank Institutional Trust Services 4 New York Plaza, 15"' Floor New York, NY 10004 54