NL-08-1093, Transmittal of Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.21)

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

ML082190066
Person / Time
Site:	Hatch, Vogtle
Issue date:	07/30/2008
From:	Aubuchon R Georgia Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-08-1093
Download: ML082190066 (84)

Text

Bin 10120 241 Ralph McGill Boulevard NE Atlanta, Georgia 30308-3374 /

Tel 404.506.6526 July 30, 2008 GEORGIAZIýý*

POWER A SOUTHERN COMPANY Docket Nos.: 50-321 50-424 NL-08-1093 50-366 50-425 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin I. Hatch Nuclear Plant Vogtle Electric Generating Plant Licensee Guarantees of Payment of Deferred Premiums (10 CFR 140.21)

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):

1. An Annual Report containing certified financial statements for calendar year 2007.

2. A set of quarterly financial statements for the period ending June 30, 2008.

3. A one year projected Cash Flows Statement for period January 1, 2009, through December 31, 2009.

Should you have any questions in connection with our response, please contact me at (404) 506-7952 or Lisa Gilbert at (404) 506-2387. This letter contains no NRC commitments.

Sincerely, Robert A. Aubuchon

Enclosures:

1. 2007 Georgia Power Company.Annual Report

2. Financial Statements - Period Ending June 30, 2008

3. Projected Cash Flows Statement - 2009 Forecast

U. S. Nuclear Regulatory Commission NL-08-1093 Page 2 cc: Southern Nuclear Operating Company Mr. J. T. Gasser, Executive Vice President Mr. J. R. Johnson, Vice President - Farley Mr. D. R. Madison, Vice President - Hatch Mr. T. E. Tynan, Vice President - Vogtle Mr. D. H. Jones, Vice President - Engineering RType: CHA02.004; CVC7000 U. S. Nuclear Regulatory Commission Mr. L. A. Reyes, Regional Administrator Mr. R. A. Jervey, NRR Project Manager - Farley Mr. R. E. Martin, NRR Project Manager - Hatch Mr. R. A. Jervey, NRR Project Manager - Vogtle Mr. E. L. Crowe, Senior Resident Inspector - Farley Mr. J. A. Hickey, Senior Resident Inspector - Hatch Mr. G. J. McCoy, Senior Resident Inspector - Vogtle

2007 Annual Report GEORGIA POWER COMPANY GEORGIA k POWER A SOUTHERN COMPANY

CONTENTS Georgia Power Company 2007 Annuai Report I

SUMMARY

2 LETTER TO INVESTORS 4 MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 5 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 6 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 28 FINANCIAL STATEMENTS 34 NOTES TO FINANCIAL STATEMENTS 67 SELECTED FINANCIAL AND OPERATING DATA 69 DIRECTORS AND OFFICERS 71 CORPORATE INFORMATION

SUMMARY

Percent 2007 2006 Change Financial Highlights (in millions):

Operating revenues $7,572 $7,246 4.5 Operating expenses $6,055 $5,736 5.6 Net income after dividends on preferred and preference stock $836 $787 6.2 Operating Datai:

Kilowatt-hour sales (in millions):

Retail 86,084 84,556 1.8 Sales for resale - non-affiliates 10,578 10,685 (1.0)

Sales for resale - affiliates 5,192 5,464 (5.0)

Total 101,854 100,705 1.1 Customers served at year-end (in thousands) 2,333 2,306 1.2 Peak-hour demand (inmegaivatts) 17,974 17,159 4.7 Capitalization Ratios (percent).

Common stock equity 50.9 53.1 Preferred and preference stock 2.1 0.4 Long-term debt (excluding amounts due within one year) 47.0 46.5 Return on Average Common Equity (percent) 13.50 13.80 Ratio of Earnings to Fixed Charges (times) 4.37 4.72 I

LETTER TO INVESTORS Georgia Power 2007 Annual Report Georgia Power achieved targeted financial results in 2007, as well as operational excellence, while taking measures to deal with the state's record drought and the nation's economic downturn. The company continued to improve its safety goals, reporting a much-improved Occupational Safety and Health Administration (OSHA) recordable incident rate over 2006.

Despite tough economic conditions nationally, Georgia remains one of the fastest-growing states in the country. With job growth and low housing costs, businesses and individuals were drawn to Georgia, increasing the number of customers Georgia Power serves to 2.3 million in 2007, a 1.2 percent increase from the previous year. Our retail sales of electricity climbed 1.8 percent in 2007.

The Georgia Public Service Commission (PSC) approved a three-year rate plan that took effect January 1, 2008. The plan provides cost recovery for the company's environmental program, as well as continued investment in electric infrastructure to meet the state's growing customer demand, while keeping our rates well below the national average.

To meet federal and state standards for emissions of nitrogen oxide (NO,), sulfur dioxide (SO 2 ),

mercury, and particulate matter, we anticipate investing $1.3 billion during the next three years.

As a result, by 2015 we plan to reduce NO, emissions by 85 percent and SO 2 emissions by 95 percent from 1990 levels and plan to achieve significant reductions in mercury and particulate matter emissions.

In addition to environmental controls, the rate plan allows us to address infrastructure needed to keep up with increasing customer demand for electricity. Today, the average residential customer uses 15 percent more electricity than customers did 10 years ago. Plus, we're serving 112,000 more customers than we did just three years ago.

In total, we need to invest $5.8 billion during the next three years to keep up with customer needs and environmental controls. This includes $1.6 billion for new generating capacity and investment in existing plants; $2.1 billion for power lines, new metering'equipment, and substations; $1.3 billion for additional environmental controls; and $800 million for nuclear fuel and other capital improvements.

In reviewing our financial results, Georgia Power's 2007 earnings totaled $836 million, a $49 million, or 6.2 percent increase from 2006. Operating revenues were $7.6 billion. We earned a 13.5 percent total company return on average common equity during 2007. Georgia Power had net plant in service of $13.3 billion at the end of 2007, with total assets of $20.8 billion.

Along with financial success, we achieved exceptional operational performance in 2007. During an August heat wave, which was compounded by. the on-going drought, our generating plants set several record peaks, including one each day from August 6 to August 9. For several days, temperatures registered more than 100 degrees, and on August 9, we-set a record peak of 17,974 megawatts.

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Continuing to look at operations, we began taking measures last year to deal with the deepening drought, which was the result of one of the driest years in the state's history. The hydro plants were the most affected, generating only half of their expected energy budget in 2007.

In an on-going effort to deal with the drought, Georgia Power enacted a number of water-saving measures, and urged all employees and the public to do everything they could to help conserve this precious resource. We will continue these efforts in 2008 and beyond.

Also last year, Georgia Power reported a 25 percent reduction in the OSHA recordable incident rate over the previous year that was attributed to more employee acceptance of our Target Zero concept.

With Target Zero, we're constantly communicating our core safety belief that safety takes precedence over all other requirements. Our first priority is to ensure the safety of our employees and the general public.

Here are highlights of several additional accomplishments in 2007:

• We opened a new transmission control center in the Georgia Power headquarters in Atlanta. It also is contracted to be the system operator for Georgia Transmission Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities transmission facilities.

• The PSC approved an Integrated Resource Plan that includes our plans to replace coal-fired generating units at Plant McDonough in metro Atlanta with natural gas units and also pilot programs for new demand-side management and energy efficiency and establishes new nuclear units as a preferred option to meet demand in 2016-2017.

" The company received high praise from President Bush, who toured Americus a few days after a tornado tore through the area last March, damaging homes and businesses and temporarily knocking out power for residents.

We stayed busy last year and were successful in so many ways - but that's business as usual for our employees. It's clear to me that the work our employees do every day and their commitment to the company are what make us successful, and it's because of their talents that we expect to remain successful.

Sincerely, Michael D. Garrett March 31, 2008 3

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Georgia Power Company 2007 Annual Report The management of Georgia Power Company (the "Company") is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met..

Under. management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2007.

This Annual Report does not include an attestation report of the Company's independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company's independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this Annual Report.

ia D. arrett Pr sident and Chief Executive Officer Cliff S. Thrasher Executive Vice President, Chief Financial Officer, and Treasurer February 25, 2008 4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Georgia Power Company We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (the "Company") (a wholly owned subsidiary of Southern Company) as of December 31, 2007 and 2006, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements (pages 28 to 65) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 to the financial statements, in 2007 the Company changed its method of accounting for uncertainty in income taxes. As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of accounting for the funded status of defined benefit pension and other postretirement plans.

T cup Atlanta, Georgia February 25, 2008 5

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Georgia Power Company 2007 Annual Report OVERVIEW Business Activities Georgia Power Company (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.

Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth, and to effectively manage and secure timely recovery of rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, and fuel prices. In December 2007, the Company completed a major retail rate proceeding (2007 Retail Rate PIan) that should provide earnings stability over the term of the 2007 Retail Rate Plan. This regulatory action also enables-the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution networks, continued generation and other investments as well as the recovery of increased operating costs. The 2007 Retail Rate Plan includes a tariff specifically for the recovery of costs related to environmental controls mandated by state and federal regulations. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. The Company is required to file a general rate case by July 1, 2010, which will determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. The Company also received regulatory orders to increase its fuel cost recovery rate effective June 1, 2005, July 1, 2006, and March 1, 2007. The Company is required to file its next fuel cost recovery case by March 1.,2008.

Key Performance Indicators In striving to maximize shareholder value while providing cost-effective energy to more than two million customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company's financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices.

Management uses customer satisfaction surveys and reliability indicators to evaluate the Company's results.

Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The 2007 fossil/hydro Peak Season EFOR of 2.23% was better than target. The nuclear generating fleet also uses Peak Season EFOR as an indicator of availability and efficient generation fleet operations during the peak season. The 2007 nuclear Peak Season EFOR of 1.23% was also better than target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2007 performance was better than target for these reliability measures. Net income after dividends on preferred and preference stock is the primary component of the Company's contribution to Southern Company's earnings per share goal.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Anniual Report The Company's 2007 results compared to its targets for some of these key indicators are reflected in the following chart:

2007 2007 Target Actual Key Performance Indicator Performance Performance Top quartile in Top quartile in Customer Satisfaction customer surveys customer surveys Peak Season EFOR - fossit/hydro 2.75% or less 2.23%

Peak Season EFOR - nuclear 2.00% or less 1.23%.

-Net Income $835 million $836 million See RESULTS OF OPERATIONS herein for additional information on the Company's financial performance. The financial performance achieved in 2007 reflects the continued emphasis that management places on these indicators, as well as the commitment shown by employees in achieving or exceeding management's expectations.

Earnings The Company's 2007 net income after dividends on preferred and preference stock totaled $836 million representing a $48.9 million, or 6.2%, increase over 2006. Operating income increased slightly in 2007 primarily due to increased operating revenues from transmission and outdoor lighting and decreased property taxes. Net income increased primarily due to higher allowance for equity funds used during construction and lower income tax expenses resulting from the Company's donation of Tallulah Gorge to the State of Georgia. This net income increase was partially offset by higher non-fuel operating expenses and increased financing costs. The Company's 2006 earnings totaled $787 million representing a $42.9 million, or 5.8%, increase over 2005. Operating income increased in 2006 due to higher base retail revenues and wholesale non-fuel revenues, partially offset by higher non-fuel operating expenses. The Company's 2005 earnings totaled $744 million representing a $61.6 million, or 9.0%, increase over 2004. Operating income increased in 2005 due to higher base retail revenues resulting from retail rate increases and favorable weather conditions, partially offset by an increase in non-fuel operating expenses.

RESULTS OF OPERATIONS A condensed income statement for the Company follows:

Increase (Decrease)

Amount from Prior Year 2007 2007 2006 2005 (in millions)

Operating revenues $ 7,572 $ 326 $ 170 $1,348 Fuel 2,641 408 296 649 Purchased power 1,050 (95) (171) 215 Other operations and maintenance 1,562 1 (11) 86 Depreciation and amortization 511 13 (28) 230 Taxes other than income taxes 291 (8) 23 33 Total operating expenses 6,055 319 109 1,213 Operating income 1,517 7 61 135 Total other income and (expense) (257) 18 (22) (19)

Income taxes 418 (25) (5) 54 Net income 842 50 44 62 Dividends on preferred and preference stock 6 1 1 Net income after dividends on preferred and preference stock $ 836 $ 49 $ 43 $ 61 7

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report OperatingRevenues Operating revenues in 2007, 2006, and 2005, and the percent of change from the prior year were as follows:

Amount 2007 2006 2005 (in millions)

Retail- prior year $ 6,205.6 $ 6,064.4 $ 5,118.8 Estimated change in -

Rates and pricing (66.2) (76.8) 270.7 Sales growth 46.5 76.6 67.4 Weather 17.7 7.5 21.7 Fuel cost recovery 294.4 133.9 585.8 Retail - current year 6,498.0 6,205.6 6,064.4 Wholesale revenues -

Non-affiliates 537.9 551.7 524.8 Affiliates 277.9 252.6 275.5 Total wholesale revenues 815.8 804.3 800.3 Other operating revenues 257.9 235.7 211.1 Total operating revenues $ 7,571.7 $ 7,245.6 $ 7,075.8 Percent change 4.5% 2.4% 23.5%

Retail base revenues were $3.8 billion in 2007. There was not a material change in total retail base revenues compared to 2006, although industrial base revenues decreased $56.5 million, or 8.5%, primarily due to lower sales and a lower contribution from market-driven rates for large commercial and industrial customers. This decrease was partially offset by a $31.8 million, or 2.1%,

increase in residential base revenues as well as a $22.6 million, or 1.5%, increase in comnmercial base revenues primarily due to higher sales from favorable weather and customer growth of 1.2%. Retail base revenues of $3.8 billion in 2006 increased $7 million, or 0.2%, from 2005 primarily due to customer growth of 1.9% and more favorable weather, partially offset by lower contributions from market-driven rates to large commercial and industrial customers. Retail base revenues of $3.8 billion in 2005 increased by

$360 million, or 10.6%, from 2004 primarily due to the retail rate increases effective January 1, 2005 and June 1, 2005, sustained economic strength, customer growth, more favorable weather, and generally higher prices to large business customers.

Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. See FUTURE EARNINGS POTENTIAL - "PSC Matters - Fuel Cost Recovery" herein for additional information.

Wholesale revenues from sales to non-affiliated utilities were:

2007 2006 2005 (in millions)

Unit power sales -

Capacity $ 33 $ 33 $ 33 Energy 33 38 32 Total 66 71 65 Other power sales -

Capacity and other 158 165 155 Energy 314 316 305 Total 472 481 460 Total non-affiliated $538 $552 $ 525 8

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Revenues from unit power sales have remained relatively constant in all periods presented. Revenues from other non-affiliated sales decreased $9.6 million, or 2.0%, in 2007, and increased $21.0 million, or 4.6%, and $273.2 million, or 146.2%, in 2006 and 2005, respectively. The decrease in 2007 was primarily due to a decrease in revenues from large territorial contracts resulting from lower emissions allowance prices. The increase in 2006 was due to a 0.6% increase in the demand for kilowatt-hour (KWH) energy sales due to a new contract with an electrical membership corporation (EMC) that went into effect in April 2006. The increase in 2005 was primarily due to contracts with 30 EMCs that went into effect in January 2005 which increased the demand for energy.

Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC).

In 2007, KWH energy sales to affiliates decreased 5.0% while revenues from sales to affiliates increased 10.0%. This was primarily due to the increased cost of fuel and other marginal generation costs. In 2006 and 2005, KWH energy sales to affiliates increased 8.5% and 2.2%, respectively, due to higher demand. However, revenues from these sales decreased by 8.3% in 2006 due to reduced cost per KWH delivered while revenues from these sales increased 59.8% in 2005 due to higher fuel prices. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Other operating revenues increased $22.2 million, or 9.4%, in 2007 primarily due to an $11.6 million increase in transmission revenues due to the increased usage of the Company's transmission system by non-affiliated companies, a $7.9 million increase in revenues from outdoor lighting activities due to a 10% increase in the number of lighting customers, and a $4.0 million increase from customer fees. Other operating revenues increased $24.6 million, or 11.6%, in 2006 primarily due to increased revenues of

$14.1 million related to work performed for the other owners of the integrated transmission system (ITS) in the State of Georgia, higher customer fees of $4.6 million, and higher outdoor lighting revenues of $6.1 million. Other operating revenues increased

$26.1 million, or 14.1%, in 2005 primarily due to higher transmission revenues of $16 million related to work performed for the other owners of the ITS, higher revenues under the open access tariff agreement, higher Outdoor lighting revenues of $5.4 million, and higher customer fees that went into effect in 2005 of $5.9 million.

Energy Sales Changes in revenues are influenced heavily by the change in volume of energy sold from year to year. KWH sales for 2007 and the percent change by year follow:

KWH Percent Change 2007 2007 2006 2005 (in billions)

Residential 26.8 2.4% 2.7% 2.7%

Commercial 33.1 2.9 2.5 6.0 Industrial 25.5 (0.3) (1.0) (5.0)

Other 0.7 5.6 (10.5) (1.0)

Total retail 86.1 1.8 1.4 1.3 Wholesale Non-affiliates 10.6 (1.0) 0.9 95.0 Affiliates 5.2 (5.0) 8.5 2.2 Total wholesale 15.8 (2.3) 3.4 50.9 Total energy sales 101.9 1.1% 1.7% 6.9%

Residential KWH sales increased 2.4% in 2007 over 2006 due to favorable weather and a 1.3% increase in residential customers.

Commercial KWH sales increased 2.9% in 2007 over 2006 primarily due to favorable weather and a 0.3% increase in commercial customers. Industrial KWH sales decreased 0.3% primarily due to reduced demand and closures within the textile industry; however, this was partially offset by a 2.9% increase in the number of industrial customers.

Residential KWH sales increased 2.7% in 2006 over 2005 due to customer growth of 1.9% and more favorable weather. Commercial KWH sales increased 2.5% in 2006 over 2005 due to customer growth of 2.0% and a reclassification of customers from industrial to 9

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report commercial to be consistent with the rate structure approved by the Georgia-Public Service Commission (PSC). Industrial KWH sales decreased 1.0% due to a 3.4% decrease in the number of customers as a result of this reclassification.

Residential KWH sales increased 2.7% in 2005 over 2004 due to more favorable weather, customer growth of 1.8%, and a 0.9%

increase in the average energy consumption per customer. Commercial KWH sales increased 6:0% in 2005 when compared to 2004 due to more favorable weather, sustained economic strength, customer growth of 1.9%, and a reclassification of customers from industrial to commercial to be consistent with the rate structure approved by the Georgia PSC. Industrial KWH sales decreased 5.0%

primarily due to this reclassification of customers.

Fuel and PurchasedPower Expenses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources forgeneration of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company's electricity generated and purchased were as follows:

2007 2006 2005 Total generation (billions of KWHs) 87.0 83.7 82.7 Total purchased power (billions of KWHs) 18.9 21.9 20.5 Sources of generation (percent)

Coal 75 75 76 Nuclear .18 18. 18 Gas 7 6 4 Hydro - 1 2 Cost of fuel, generated (cents per net KWH)

Coal 2.87 2.58 1.91 Nuclear' 0.51 0.47 0.47 Gas 6.28 5.76 14.03 Average cost of fuel, generated (cents per net KWH) 2.68 2.39 2.12 Average cost of purchased power (cents per net KWH) 7.27 6.38 7.51 Fuel and purchased power expenses were $3.7 billion in 2007, an increase of $312.9 million, or 9.3%, above prior year costs. This increase was driven by a $414.5 million increase in total energy costs due to the higher average cost of fuel and purchased power.

This was partially offset by a $101.6 million reduction due to less KWHs purchased.

Fuel and purchased power expenses were $3.4 billion in 2006, an increase of $124.4 million, or 3.8%, above prior year costs. This increase was driven by a $146.1 million increase related to higher KWHs generated and purchased partially offset by a $21.7 million decrease in the average cost of fuel and purchased power.

Fuel and purchased power expenses were $3.3 billion in 2005, an increase of $863.4 million, or 36.1%, above prior year costs. This increase was the result of an $881.2 million increase in the average cost of fuel and purchased power partially offset by a

$17.8 million decrease related to total lower KWHs generated and purchased.

In 2007, the Company entered into power purchase agreements (PPAs) with companies to purchase a total of approximately 1,795 megawatts (MW). These contracts start in 2010. These agreements have been approved by the Georgia PSC and the FERC, as required. Of the total capacity, approximately 561 MW will expire in 2017, 292 MW in 2025, and 942 MW in 2030. These contracts are expected to result in higher non-fuel expenses that will be subject to recovery through future base rates. Additionally, in December 2007 and January 2008, the Company entered into two biomass renewable generation contracts for 50 MW each. Both contracts begin in 2010 and one expires in 2025 and the other expires in 2030.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report In 2006, the Company entered into three PPAs to purchase a total of approximately 1,000 MW annually from June 2009 through May 2024. These agreements were approved by the Georgia PSC.

These agreements satisfy growth and replace expiring agreements. The agreements are expected to result in higher non-fuel expenses that will be subject to recovery through future base rates.

While there has been a significant upward trend in the cost of coal and natural gas since 2003, prices moderated somewhat in 2006 and 2007. Coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases inrnining and fuel transportation costs. While demand for natural gas in the United States continued to increase in 2007, natural gas supplies have also risen due to increased production and higher storage levels. During 2007, uranium prices were volatile and .increased over the course of the year due to increasing long-term demand, with primary production levels at approximately 55% to 60% of demand.

Secondary supplies and inventories were sufficient to fill the primary production shortfall.

Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company's fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL "PSC MATTERS -Fuel Cost Recovery" for additional information.

Other Operations and Maintenance Expenses In 2007, the total change in other operations and maintenance expenses was immaterial compared to 2006.

In 2006, other operations and maintenance expenses decreased $11.0 million, or 0.7%, from the prior year. Maintenance for generating plants decreased $20.0 million in 2006 as a result of fewer scheduled outages than 2005, offset by an increase of

$18.2 million for transmission and distribution expenses related to load dispatching and overhead line maintenance. Also contributing to the decrease were lower employee benefit expenses related to medical benefits and lower workers compensation expense of

$23.2 million, partially offset by lower pension income of $13.7 million.

In 2005, other operations and maintenance expenses increased $86 million, or 5.8%. Maintenance for generating plant and transmission and distribution increased $27.5 million and $15.9 million, respectively, as a result of scheduled outages and, to a lesser extent, certain flexible projects planned for other periods. Increased employee benefit expense of $18.9 million related to pension and medical benefits and higher property insurance costs of $4.6 million resulting from storm damage also contributed to the increase.

Customer assistance expense and uncollectible account expense also increased an additional $9.3 million in 2005 over 2004, primarily as a result of promotional expenses related to an energy efficiency program and an increased number of customer bankruptcies.

Depreciation and Amortization Depreciation and amortization increased $12.4 million, or 2.5%, in 2007 from the prior year primarily due to a 3.4% increase in plant in service from the prior year. This increase was partially offset by a decrease 'in amortization due' to a regulatory liability related to the inclusion of certified PPAs in retail rates as ordered by the Georgia PSC under the terms of the retail r Iate plan for the three ye ars ended December 31, 2007 (2004 Retail Rate Plan). Depreciation and amortization decreased $27.9 million, or 5.3%, in 2006 from the prior year due to the scheduled decrease in amortization related to this regulatory liability. This decrease was partially offsej by a

$15.9 million, or 3.2%, increase in depreciation expense in 2006 over 2005 due to an increase in plant in service. Depreciation and amortization increased $230 million, or 77.5%, in 2005 over 2004 primarily due to the expiration at the end of 2004 of certain accelerated amortization provisions of the previously existing retail rate plan. See Note 3 to the financial statements under "Retail Regulatory Matters - Rate Plans" for additional information.

Taxes Other than Income Taxes Taxes other than income taxes decreased $7.7 million, or 2.6%, in 2007 primarily due to the resolution of a dispute regarding property taxes in Monroe County, Georgia. See Note 3 to the financial statements under "Property Tax Dispute" for additional information.

Taxes other than income taxes increased $22.8 million, or 8.3%, in 2006 primarily due to higher property taxes of $13.3 million as a result of an increase in-property values and higher municipal gross receipts taxes of $9.1 million as a result of increased retail operating revenues. Taxes other than income taxes increased $33 million, or 13.6%, in 2005 primarily due to higher municipal gross receipts taxes of $18.1 million resulting from increased retail operating revenues and higher property taxes of $14.0 million.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Allowance for Equity Funds Used DuringConstruction Allowance for equity funds used during construction (AFUDC) increased $36.7 million, or 116.3%, in 2007 primarily due to the increase in the Company's construction work in progress balance related to ongoing transmission, distribution, and environmental projects. AFUDC remained relatively constant in 2006 and 2005.

Interest Expense, Net of Amounts Capitalized Interest expense increased $25.5 million, or 8.0%, in 2007 primarily due to a 13.9% increase in long-term debt levels due to the issuance of additional senior notes and pollution control bonds. Interest expense increased $22.5 million, or 7.6%, in 2006 primarily due to generally higher interest rates on variable rate debt and commercial paper, the issuance of additional senior notes, and higher average balances of short-term debt. Interest expense increased $40.6 million, or 15.9%, in 2005 primarily due to the issuance of additional senior notes and generally higher interest rates on variable rate debt and commercial paper.

Other Income and (Expense), Net Other income and (expense), net increased $5.8 million, or 66.5%, in 2007 primarily due to $4.0 million from land and timber sales.

Other income and (expense), net increased $1.9 million, or 26.7%, in 2006 primarily due to reduced expenses of $2.9 million and

$5.0 million related to the employee stock ownership plan and charitable donations, respectively, and increased revenues of

$3.6 million, $5.4 million, and $3.4 million related to a residential pricing program, customer contracting, and customer facilities charges, respectively. These increases were partially offset by net financial gains on gas hedges of $18.6 million in 2005. Other income and (expense), net increased $21.5 million in 2005 from 2004, or 148.0%, primarily due to $16.8 million of additional gas hedge gains.

Income Taxes Income taxes decreased $24.8 million, or 5.6%, in 2007 primarily due to state and federal deductions for the Company's donation of 2,200 acres in the Tallulah Gorge area to the State of Georgia and higher federal manufacturing deductions. In 2006, income taxes decreased $5.1 million, or 1.1%, primarily due to the recognition of state tax credits. In 2005, income taxes increased $53.5 million, or 13.6%, primarily due to higher pre-tax net income. See Note 5 to the financial statements for additional information.

Effects of Inflation The Company is subject to rate regulation that is based on the recovery of historical costs. When historical costs are included, or when inflation exceeds projected costs used in rate regulation or market-based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, income tax laws are based on historical costs. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt, preferred securities, preferred stock, and preference stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company's approved electric rates.

FUTURE EARNINGS POTENTIAL General 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. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for electricity relating to PPAs, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Retail rates and revenues are reviewed and adjusted periodically with certain limitations. See ACCOUNTING POLICIES - "Application of Critical Accounting Policies and Estimates - Electric Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" and "FERC Matters" for additional information about regulatory matters.

12

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings 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 price of electricity, the price elasticity of demand, and the rate of economic growth in the Company's service area.

Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. Under the 2007 Retail Rate Plan approved by the Georgia PSC on December 18, 2007, an environmental compliance cost recovery (ECCR) tariff was implemented on January 1,2008 to allow for the recovery of most of the costs related to environmental controls mandated by state and federal regulation scheduled for completion in 2008, 2009, and 2010. See Note 3 to the financial statements under "Rate Plans" for additional information.

New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and the Company, alleging that these.

subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities including the Company's Plants Bowen and Scherer. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the.

EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government's claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power's motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA's claims related to the four remaining plants.

The plaintiffs appealed the district court's decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court's decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court's Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court's decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court's decision in the Duke Energy case.

The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

The EPA has issued a series of proposed and final revisions to its NSR regulations under the Clean Air Act, many of which have been subject to legal challenges by environmental groups and states. In June 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA's revisions to NSR regulations that were issued in December 2002 but vacated portions of those 13

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report revisions addressing the exclusion of certain pollution control projects. These regulatory revisions have been adopted by the State of Georgia. In March 2006, the U.S: Court of Appeals for the District of Columbia Circuit also vacated an EPA rule which sought to clarify the scope of the existing routine maintenance, repair, and replacement exclusion. The EPA has also published proposed rules clarifying the test for determining when an emissions increase subject to the NSR permitting requirements has occurred. The impact of these proposed rules will depend on adoption of the final rules by the EPA and the State of Georgia's implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

CarbonDioxide Litigation In July 2004, attorneys general from eight states, each outside of Southern Company's service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies' emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection withtheir claims.

Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U*S. District Court for the Southern District of New York granted Southern Company's and the other defendants' motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.

EnvironmentalStatutes and Regulations General The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning,& Community Right-to-Know Act; and the Endangered Species Act. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2007, the Company had invested approximately $2.4 billion in capital projects to comply with these requirements, with annual totals of $856 million, $351 million, and

$117 million for 2007, 2006, and 2005, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes, and regulations will be an additional $707 million, $353 million, and $246 million for 2008, 2009, and 2010, respectively. The Company's compliance strategy is impacted by changes to existing environmental laws, statutes and regulations, the cost, availability, and existing inventory of emission allowances, and the Company's fuel mix. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements and Contractual Obligations" herein.

Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company's operations; however; the full impact of any such changes cannot be determined at this time.

Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company.

Through 2007, the Company had spent approximately $2.1 billion in reducing sulfur dioxide (SO 2 ) and nitrogen oxide (NOJ) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO 2 , NO,, and mercury emissions, maintain compliance with existing regulations, and meet new requirements.

In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. Areas within the Company's service area that were designated as nonattainment under the eight-hour ozone standard include Macon and a 20-county area within metropolitan Atlanta. The Macon area was redesignated by the EPA as an attainment area on September 19, 2007. In December 2006, the 14

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report U.S. Court of Appeals for the District of Columbia Circuit vacated the first set of implementation rules adopted in 2004 and remanded the rules to the EPA for. further refinement. On June 20, 2007, the EPA proposed additional revisions to the current eight-hour ozone standard which, if enacted, could result in the designation of new nonattainment areas within the Company's service territory. The EPA has requested comment and is expected to publish final revisions to the standard in 2008. The impact of this decision, if any, cannot be determinedat this time and will depend on subsequent'legal action and/or, future nonattainment designations and state regulatory plans.

During 2005, the EPA's fine particulate matter nonattainment designations became effective for several areas within the Company's service area. State plans for addressing the nonattainment designations under the existing standard are required by April 2008 and could require further reductions in SO 2 and NO, emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. In December 2007, state agencies recommended to the EPA that an area encompassing all or parts of 22 counties within metropolitan Atlanta be designated as nonattainment for this standard. The EPA plans to designate nonattainment areas based on the new standard by December 2009. The ultimate outcome of this matter depends on the development and submittal of the required state plans and the resolution of pending legal challenges and, therefore, cannot be determined at this time.

The EPA issued the final Clean Air Interstate Rule in March 2005. This cap-and-trade rule addresses power plant SO 2 and NO, emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states,;including the State of Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NO, and/or SO 2 to be achieved in two phases, 2009/2010 and 2015. The State of Georgia has completed plans to implement this program. These reductions will be accomplished by the installation of additional emission controls at the Company's coal-fired facilities and/or by the purchase of emission allowances from a cap-and-trade program. The State of Georgia implemented the Clean Air Interstate Rule, and in June 2007, approved a "multi-pollutant rule" that will require plant specific emission controls on all but the smallest generating units in Georgia according to a schedule set forth in the rule. The rule is designed to ensure reductions in emissions of SO 2 , NO,, and mercury in Georgia.

The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO, and NO,.

Extensive studies were performed for each of the Company's affected units to demonstrate that additional particulate matter controls are not necessary under BART. At the request of the State of Georgia, additional analyses were performed for certain units in Georgia to demonstrate that no additional SO 2 controls were required. States are currently completing implementation plans that contain strategies for BART and any other measures required to achieve the first phase of reasonable progress.

The impacts of the eight-hour ozone and the fine particulate matter nonattainment designations, and the Clean Air Visibility Rule on the Company will depend on the development and implementation of rules at the state level. Therefore; the full effects of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO 2 and NO, emission controls within the next several years to assure continued compliance with applicable air quality requirements.

In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court issued its ruling and vacated the Clean Air Mercury Rule. The Company's overall environmental compliance strategy relies primarily on a combination of S02 and NOx controls to reduce mercury emissions.

Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings could require emission reductions more stringent than required by the Clean Air Mercury Rule.

15

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Water Quality In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures..

The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. On January 25,.2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA's use of "cost-benefit" analysis and suggested some ways to incorporate cost considerations. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules' implementation, and the actual requirements established by State of Georgia regulatory agencies and, therefore, cannot be determined at this time.

Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties.

The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters - Environmental Remediation" for additional information.

Global Climate Issues Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions continue to be considered in Congress. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company's greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company's greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on July 13, 2007, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. Included in the orders is a directive to the Florida Secretary of Environmental Protection to develop rules adopting maximum allowable emissions levels of greenhouse gases for electric utilities, consistent with the statewide emission reduction targets, and a request to the Florida PSC to initiate rulemaking requiring utilities to produce at least 20% of their electricity from renewable sources. The impact of any similar state requirements on the Company will depend on the development, adoption, and implementation of state laws or rules governing greenhouse gas emissions, and the ultimate outcome cannot be determined at this time.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue.

Current efforts focus on a potential successor to the Kyoto Protocol for the post 2008 through 2012 timeframe. The outcome and impact of the international negotiations cannot be determined at this time.

The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.

16

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report FERC Matters Market-BasedRate Authority The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

In December 2004, the FERC initiated a proceeding to assess Southern Company's generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company's retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.

In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used inwthe generation' dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding canrot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-bas6d rates for certain wholesale sales in the Southern Company retail servicd territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $5.8 million, plus interest.

The Company believes that there is nomeritorious basis for this proceeding and is vigorously defending itself in this matter.

On June 21, 2007, the FERC issued 'its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.

Intercompany InterchangeContract-The Company's generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern PoWer, and Southern Company Services, Inc. (SCS), as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC's standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company's code of conduct defining Southern Power as a "system company" rather than a "marketing affiliate" is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power's inclusion in the IIC in 2000. The FERC also previously approved Southern Company's code of conduct.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company's agreement to accept certain modifications to the settlement's terms and Southern Company notified the FERC that it accepted the modifications.

The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, With certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company's financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.

GenerationInterconnectionAgreements In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.

On January 19, 2007, the FERC issued an order granting Tenaska's requested relief. Although the FERC's order required the modification of Tenaska's interconnection agreements, under the provisions of the order the Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of the FERC's methodology for determining the amount of refunds. The requested rehearings were denied and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.

17

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report PSC Matters Rate Plans In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan for the years 2008 through.2010. Under the 2007 Retail Rate Plan, the Company's earnings will continue to be evaluated against a retail return on common equity (ROE) range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to an ECCR tariff. The Company agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. Retail base rates increased by approximately $99.7 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs for required environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008.

The Company is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. See Note 3 to the financial statements under "Retail Regulatory Matters - Rate Plans" for additional information.

Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Georgia PSC. In March 2006, the Company and Savannah Electric filed a combined request for fuel cost recovery rate changes with the Georgia PSC to be effective July 1, 2006, concurrent with the merger of the companies. In June 2006, the Georgia PSC ruled on the request and approved an increase in the Company's total annual billings of approximately $400 million. The Georgia PSC order provided for a combined ongoing fuel forecast but reduced the requested increase related to such forecast by $200 million. With respect to the merger, the Georgia PSC also set a Merger Transition Adjustment (MTA) applicable to customers in the former Savannah Electric service territory so that the fuel rate that became effective on July 1, 2006 plus the MTA equaled the applicable fuel rate paid by such customers as of June 30, 2006.

Amounts collected under the MTA were credited to customers in the original Georgia Power service territory through a Merger Transition Credit (MTC) through December 31, 2007. The order also required the Company to file for a new fuel cost recovery rate on a semi-annual basis, beginning in September 2006. Accordingly, in September 2006, the Company filed a request to recover fuel costs incurred through August 2006 by increasing the fuel cost recovery rate. In November 2006, under agreement with the Georgia.

PSC staff, the Company filed a supplementary request reflecting a forecast of annual fuel costs, as well as updated information for previously incurred fuel costs.

On February 6, 2007, the Georgia PSC approved an increase in the Company's total annual billings of approximately $383 million effective March 1, 2007. The order reduced the Company's requested increase in the forecast of annual fuel costs by $40 million and disallowed $4 million of previously incurred fuel costs. Estimated under recovered fuel costs through February 2007 are to be recovered through May 2009 for customers in the original Georgia Power territory and through November 2009 for customers in the former Savannah Electric territory. The order also requires the Company to file for a new fuel cost recovery rate no later than March 1, 2008. As of December 31, 2007, the Company had a total under recovered fuel cost balance of approximately $692 million, of which approximately $106 million is not included in current rates.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on the Company's revenues or net income, but does impact annual cash flow. In accordance with Georgia PSC order, approximately $307 million of the under recovered regulatory clause revenues for the Company is included in deferred charges and other assets at December 3 1, 2007.

See Note 1 to the financial statements under "Revenues",and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.

Income Tax Matters GeorgiaState Income Tax Credits The Company's 2005 through 2007 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. The Company has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. On July 24, 2007, the Company filed a complaint in the Superior Court of Fulton 18

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report County to recover the credits claimed for the years 2002 through 2004. If allowed, these claims could have a significant, possibly material, positive effect on the Company's net income. If the Company is not successful, payment of the related state tax could have a significant, possibly material, negative effect on the Company's cash flow. The ultimate outcome of this matter cannot now be determined. See Note. 3 under "Income Tax Matters" and Note 5 under "Unrecognized Tax Benefits" for additional information.

InternalRevenue Code Section 199 Domestic ProductionDeduction The American Jobs Creation Act of 2004 created a tax deduction for the portion of income attributable to U.S. production activities as defined in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 (production activities deduction).

The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9%

rate applicable for all years after 2009. See Note 5 to the financial statements under "Effective Tax Rate" for additional information.

Bonus Depreciation On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (Stimulus Act) into law. The Stimulus Act includes a provision that allows 50% bonus depreciation for certain property acquired in 2008 and placed in service in 2008, or in limited circumstances, 2009. The Company is currently assessing the financial implications of the Stimulus Act; however, the ultimate impact cannot be determined at this time.

Nuclear NuclearProjects In August 2006, as part of a potential expansion of Plant Vogtle, the Company and Southern Nuclear Operating Company, Inc. (SNC) filed an application with the Nuclear Regulatory Commission (NRC) for an early site permit (ESP) on behalf of the owners of Plant Vogtle. In addition, the Company and SNC notified the NRC of their intent to apply for a combined construction and operating license (COL) in 2008. Ownership agreements have been signed with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. In June 2006, the Georgia PSC approved the Company's request to establish an accounting order that would allow the Company to defer for future recovery the ESP and COL costs, of which the Company's portion is estimated to total approximately $51 million. At December 31, 2007, approximately $28.4 million is included in deferred charges and other assets. At this point, no final decision has been made regarding actual construction. Any new generation resource must be certified by the Georgia PSC in a separate proceeding.

Nuclear Relicensing In January 2002, the NRC granted the Company a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of Units 1 and 2 until 2034 and 2038, respectively. The Company filed an application with the NRC in June 2007 to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. The Company anticipates the NRC may make a decision regarding the license extension for Plant Vogtle as early as 2009.

Other Matters The Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company's financial statements. See Note 3 to the financial statements for information regarding material issues.

19

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States.

Significant accounting policies are described in Note I to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements.

Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Electric Utility Regulation The Company is subject to retail regulation by the Georgia PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies Financial Accounting Standards Board (FASB) Statement No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71),

which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of SFAS No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company's results of operations than they would on a non-regulated company.

As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.

Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's financial statements. These events or conditions include the following:

• Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality,

-control of toxic substances, hazardous and solid wastes, and other environmental matters.

Changes in existing income tax regulations or changes in Internal Revenue Service (IRS) or Georgia DOR interpretations of existing regulations.

Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.

• Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.

• Resolution or progression of existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA.

20

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Unbilled Revenues Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated.

Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company's results of operations.

New Accounting Standards Income Taxes On January 1, 2007, the Company adopted FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" (FIN 48),

which requires companies to determine whether it is "more likely than not" that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. The provisions of FIN 48 were applied to all tax positions beginning January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company's financial statements. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Pensions and Other PostretirementPlans On December 31, 2006, the Company adopted FASB Statement No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans" (SFAS No. 158), which requires recognition of the funded status of its defined benefit postretirement plans in the'balance sheets. Additionally, SFAS No. 158 will require the Company to change the measurement date for its defined benefit postretirement plan assets and obligations from September 30 to December 31 beginning with the year ending December 31, 2008. See Note 2 to the financial statements for additional information.

Fair Value Measurement The FASB issued FASB Statement No. 157, "Fair Value Measurements" (SFAS No. 157) in September 2006. SFAS No. 157 provides guidance on how to measure fair value where it is permitted or required under other accounting pronouncements. SFAS No. 157 also requires additional disclosures about fair value measurements. The Company adopted SFAS No. 157 in its entirety on January 1, 2008, with no material effect on its financial condition or results of operations.

Fair Value Option In February 2007, the FASB issued FASB Statement No. 159, "Fair Value Option for Financial Assets and Financial Liabilities -

Including an Amendment of FASB Statement No. 115" (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008, with no material effect on its financial condition or results of operations.

FINANCIAL CONDITION AND LIQUIDITY Overview The Company's financial condition remained stable at December 31, 2007. Cash flow from operations totaled $1.4 billion, an increase of $248.5 million from 2006, primarily due to higher retail revenues primarily related to higher fuel cost recovery revenues and less cash used for working capital primarily from lower inventory additions and increases in other current liabilities. Cash flow from operations increased $117.4 million in 2006, primarily from increased retail operating revenues partially offset by higher fuel inventories and an increase in under recovered deferred fuel costs. In 2005, cash flow from operations increased $58.4 million primarily from increased retail operating revenues, partially offset by the increase in under recovered deferred fuel costs.

21

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Net cash used for investing activities totaled $1.9 billion due to gross property additions primarily related to installation of equipment to comply with environmental standards, construction of transmission and distribution facilities, and purchase of nuclear fuel. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, capital contributions from Southern Company, and the issuance of long and short-term debt and preference stock.

Cash provided from financing activities totaled $429.7 million primarily related to the issuance of new senior notes. The statements of cash flows provide additional details. See "Financing Activities" herein.

Significant balance sheet changes in 2007 include a $726 million increase in long-term debt and a $221 million increase in Preferred and Preference Stock primarily to replace short-term debt and provide funds for the Company's continuous construction programs.

Other balance sheet changes include an increase in total property, plant and equipment of $1.3 billion and a $206 million decrease in the under recovered fuel balance.

The Company's ratio of common equity to total capitalization - including short-term debt - was 47.5% in 2007, 48.6% in 2006, and 47.9% in 2005. The Company has received investment grade ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and preference stock.

Sources of Capital The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approvals, and other factors. The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short-term debt securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended. The amounts of securities authorized by the Georgia PSC and the FERC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.

The Company's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source for under recovered fuel costs and to meet cash needs which can fluctuate significantly due to the seasonality of the business.

To meet short-term cash needs and contingencies, at the beginning of 2008 the Company had credit arrangements with banks totaling

$1.2 billion, of which $8 million was used to support an outstanding letter of credit. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

At the beginning of 2008, bank credit arrangements were as follows:

Expires Total Unused 2008 2012 (in millions)

$1,160 $1,152 $40 $1,120 The credit arrangement that expires in 2008 allows for the execution of term loans for an additional two-year period.

The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from issuances for the benefits of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. As of December 31, 2007, the Company had $616 million of outstanding commercial paper and a $100 million short-term bank loan outstanding.

22

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Financing Activities During 2007, the Company issued $1.5 billion of senior notes and $225 million of preference stock and incurred $191 million of obligations related to the issuance of pollution control bonds. The issuances were used to reduce the Company's short-term indebtedness, fund senior note maturities totaling $300 million, redeem $763 million of long-term debt payable to affiliated trusts, and fund the Company's ongoing construction program.

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

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2007, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $9 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $515 million.

The Company is also party to certain agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade for the Company and/or Alabama Power. These agreements are primarily for natural gas and power price risk management activities. At December 31, 2007, the Company's total exposure related to these types of agreements was approximately $15 million.

Market Price Risk Due to cost-based rate regulation, the Company has limited exposure to market rate volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and hedging practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis.

To mitigate future exposure to changes in interest rates, the Company enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. These derivatives have a notional amount of $539 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on $1.4 billion of outstanding variable long-term debt that has not been hedged at January 1, 2008 was 4.5%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $14.2 million at January 1, 2008. Subsequent to December 31, 2007, the Company converted $115 million of floating rate pollution control bonds to a fixed rate mode. Additionally, the Company entered into floating to fixed interest rate swaps on $601 million of variable rate long-term debt. These actions reduced the Company's exposure to variable rate debt to $704 million for the remainder of the year.

Subsequent to these actions, a 100 basis point change in interest rates for all unhedged variable rate long-term debt would affect annualized interest expense by $7.7 million. See Notes 1 and 6 to the financial statements under "Financial Instruments" for additional information.

The Company's $704 million of variable interest rate exposure relates to tax-exempt auction rate pollution control bonds. Recent weakness in the auction markets has resulted in higher interest rates. The Company has sent notice of conversion of $662 million of these auction rate securities to alternative interest rate determination methods and plans to remarket all remaining auction rate securities in a timely manner. None of the securities are insured or backed by letters of credit that would require approval of a guarantor or security provider. It is not expected that the higher rates as a result of the weakness in the auction markets will be material.

To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for gas purchases.

23

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report The Company has implemented a fuel hedging program at the instruction of the Georgia PSC. The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:

Changes in Fair Value 2007 2006 (in millions)

Contracts beginning of year $ (38.0) $ 35.3 Contracts realized or settled 41.6 40.2 New contracts at inception - -

Changes in valuation techniques Current period changes(a) (4.0) (113.5)

Contracts end of year $ (0.4) $ (38.0)

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

Source of 2007 Year-End Valuation Prices Total Maturity Fair Value Year 1 1-3 Years (in millions)

Actively quoted $ (1.1) $ (5.8) $ 4.7 External sources 0.7 0.7 -

Models and other methods - - -

Contracts end of year $ (0.4) $ (5.1) $ 4.7 Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company's fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company's fuel cost recovery mechanism. The Company realized net losses in 2007 and 2006 of $68 million and $66 million, respectively. Through June 30, 2006, the Company was allowed to retain 25% of net financial gains in earnings, and in 2005 the Company had a total net gain of $74.6 million of which the Company retained $18.6 million. See Note 3 to the financial statements under "Retail Regulatory Matters - Fuel Hedging Program" for additional information. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2007, the fair value gains (losses) of energy-related derivative contracts were reflected in the financial statements as follows:

Amounts (in millions)

Regulatory assets, net $ (0.4)

Net income Total fair value $ (0.4)

Unrealized gains (losses) recognized in income were not material for any year presented. The Company is exposed to 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 I and 6 to the financial statements under "Financial Instruments."

24

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to be $2.0 billion for 2008, $2.0 billion for 2009, and $1.8 billion for 2010. Environmental expenditures included in these estimated amounts are $707 million, $353 million, and $246 million for 2008, 2009, and 2010, respectively. Actual construction costs may vary from these estimates because of changes in such factors as: business conditions; environmental statutes and regulations; nuclear plant regulations; FERC rules and 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.

As a result of requirements by the NRC, the Company has established external trust funds for nuclear decommissioning costs. For additional information, see Note I to the financial statements under "Nuclear Decommissioning."

In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC and the FERC.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities and the related interest, preferred and preference stock dividends, leases, derivative obligations, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

25

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Contractual Obligations 2009- 2011- After Uncertain 2008 2010 2012 2012 Timing (d) Total (in millions)

Long-term debt(a)

Principal $ 199 $ 283 $ 403 $ 5,257 $ 6,142 Interest 323 611 593 5,730 7,257 Preferred and preference stock dividends(b) 17 35 35 87 Derivative obligations(c)-

Commodity 9 9 Interest 14 3 17 Operating leases 29 49 34 29 - 141 Unrecognized tax benefits and interest(d) 96 96 Purchase commitments(') -

Capital(' 1,915 3,497 - 5,412 Limestone (g) 5 29 30 51 - 115 Coal 1,653 1,519 129 21 - 3,322 Nuclear fuel 116 266 220 125 - 727 Natural gas(h) 684 732 761 2,803 - 4,980 Purchased power 342 690 581 2,345 - 3,958 Long-term service agreements'i) 12 27 58 637 - 734 Trusts -

Nuclear decommissioningo) 7 7 7 56 77 Postretirement benefits(k) 23 46 69 Total $5,348 $7,794 $2,851 $ 17,054 $ 96 $ 33,143 (a) All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1,2008, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.

(b) Preferred and preference stock does not mature; therefore, amounts provided are for the next five years only.

(c) For additional information see Notes 1 and 6 to the financial statements.

(d) The timing related to the realization of $96 million in unrecognized tax benefits and interest payments cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. Of this $96 million, $71 million is the estimated cash payment. See Note 3 and Note 5 to the financial statements for additional information.

(e) The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $1.6 billion, $1.6 billion, and $1.6 billion, respectively.

(f) The Company forecasts capital expenditures over a three-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 3 1,2007, significant purchase commitments were outstanding in connection with the construction program.

(g) As part of the Company's program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment.

(h) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2007.

(i) Long-term service agreements include price escalation based on inflation indices.

(j) Projections of nuclear decommissioning trust contributions are based on the 2007 Retail Rate Plan.

(k) 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 and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company's corporate assets.

26

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2007 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company's 2007 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, fuel cost recovery, environmental regulations and expenditures, the Company's projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates,"

"believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology.

There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in 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 FERC matters and the pending EPA civil action against the Company;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

• variations in demand for electricity, including those relating to weather, the general economy, population, business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuel;

• effects of inflation;

• ability to control costs;

• investment performance of the Company's employee benefit plans;

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases related to fuel cost recovery;

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

• potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

• the ability of counterparties of the Company to make payments as and when due;

• the ability to obtain new short- and long-term contracts with neighboring utilities;

• the direct or indirect effect on the Company's business resulting from terrorist incidents and the threat of terrorist incidents;

• interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;

• the ability of the Company to obtain additional generating capacity at competitive prices;

• catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian influenza, or other similar occurrences;

• the direct or indirect effects on the Company's business resulting from incidents similar to the August 200.3 power outage in the Northeast;

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

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

The Company expressly disclaims any obligation to update any forward-looking statements.

27

STATEMENTS OF INCOME For the Years Ended December 31, 2007, 2006, and 2005 Georgia Power Company 2007 Annual Report 2007 2006 2005 (in thousands)

Operating Revenues:

Retail revenues $6,498,003 $6,205,620 $6,064,363 Wholesale revenues -

Nonl-affiliates 537,913 551,731 524,800 Affiliates 277,832 252,556 .275,525 Other revenues 257,904 235,737 211,149 Total operating revenues 7,571,652 7,245,644 7,075,837 Operating Expenses:

Fuel 2,640,526 2,233,029 1,937,378 Purchased power -

Non-affiliates 332,064 332,606 421,033 Affiliates 718,327 8129'33 895,243 Other operations 1,016,608 ,.1,025,848 1,00.9,993 Maintenance 545,128 534,621 561,464 Depreciation and amortization 511,180 498,754 526,652 Taxes other than income taxes 291,136 298,824 276,027 Total operating expenses 6,054,969 5,736,115 5,627,790 Operating Income 1,516,683 1,509,529 1,448,047 Other Income and (Expense):

Allowance for equity funds used during construction 68,177 31,524 29,145 Interest income 3,560 2,459 6,537 Interest expense, net of amounts capitalized (343,462) '(317,947) (295,486)

Other income (expense), net 14,705 8,833 16,971 Total other income and (expense) .(257,020) (275,131) (252,833)

Earnings Before Income Taxes 1,259,663 1,234,398 1,195,214 Income taxes 417,521 442,334 447,448 Net Income 842,142 792,064 747,766 Dividends on Preferred and Preference Stock 6,006 4,839 3,393 Net Income After Dividends on Preferred and Preference Stock $836,136 $787225 $744,373 The accompanying notes arc an integral part of these financial statements.

28

STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2007, 2006, and 2005 Georgia Power Company 2007 Annual Report 2007 2006 2005 (in thousandsj Operating Activities:

Net income $ 842,142 $ 792,064 $ 747,766 Adjustments to reconcile net incomt to net cash provided from operating activities -.

Depreciation and amortization 616,796 588,428 616,963 Deferred income taxes and investment tax credits, net (78,010) 16,159 257,501 Allowance for equity funds used during construction (68,177) (31,524) (29,145)

Pension, postretirement, and other employee benefits 8,836 18,604 (13,335)

Stock option expense 5,977 5,805 -

Tax benefit of stock options 1,811 1,163 17,263 Other, net 33,731 3,293 (6,933)

Changes in certain current assets and liabilities -.

Receivables 134,276 1,193 (650,593)

Fossil fuel stock (1,211) (194,256) (2,898)

Materials and supplies (32,998) 31,317 (55,805)

Prepaid income taxes 10,002 1,060 (38,975)

Other current assets (4,359) 774 3,585 Accounts payable 22,626 (85,189) 122,117 Accrued taxes (33,320) 82,735 77,164 Accrued compensation (30,039) (10,328) 4,162 Other current liabilities 20,703 (21,054) 34,029 Net cash provided from operating activitie, 1,448,786 1,200,244 1,082,866 Investing Activities:

Property additions (1,765,344) (1,219,498) (891,314)

Investment in restricted cash from pollution control bonds (59,525)

Nuclear decommissioning trust fund purchases (448,287) (464,274) (381,235)

Nuclear decommissioning trust fund sales 441,407 457,394 372,536 Cost of removal net of salvage (47,565) (33,620) (30,764)

Change in construction payables, net of joint owner portion 24,893 35,075 4,190 Other (25,479) (16,005) (788)

Net cash used for investing activitie. (1,879,900) (13240,928) (927,375)

Financing Activities:

Increase (decrease) in notes payable, net (17,690) 406,768 97,713 Proceeds --

Senior notes 1,500,000 150,000 625,000 Preferred and preference stock 225,000 - -

Pollution control bonds 190,800. 153,910 185,000 Gross excess tax benefit of stock options 4,695 2,796. -

Capital contributions from parent company 322,448 312,544 149,475 Redemptions ..

Pollution control bonds (153,910) (185,000)

Capital leases (2,185) (136) (1,095)

Senior notes (300,000) (150,000) (450,000)

First mortgage bonds (20,000)

Preferred and preference stock (14,569)

Other long-term debil (762,887)

Payment of preferred and preference stock dividends (3,143) (2,958) (3,246)

Payment of common stock dividends (689,900) (630,000) (582,800)

Other . (37,482) . (8,049) (21,760)

Net cash provided from (used for) financing activitie, 429,656 46,396 (186,713)

Net Change in Cash and Cash Equivalents (1,458) 5,712 (31,222)

Cash and Cash Equivalents at Beginning of Year 16,850 11,138 42,360 Cash and Cash Equivalents at End of Year $ 15,392 $ 16,850 " $ 11,138 Supplemental Cash Flow Information:

Cash paid during the period for --

Interest (net of $28,668, $12,530, and $11,949 capitalized, respectively, $317,938 $317,536 $263,802 Income taxes (net of refunds) 456,852 398,735 196,930 The accompanying notes are an integral part of these financial statements.

29

BALANCE SHEETS At December 31, 2007 and 2006 Georgia Power Company 2007 Annual Report Assets 2007 2006 (in thousands)

Current Assets:

Cash and cash equivalents $ 15,392 $ 16,850 Restricted cash 48,279 -

Receivables --

Customer accounts receivable 491,389 474,046 Unbilled revenues 137,046 130,585 Under recovered regulatory clause revenues 384,538 353,976 Other accounts and notes receivable 147,498 93,656 Affiliated companies 21,699 21,941 Accumulated provision for uncollectible accounts (7,636) (10,030)

Fossil fuel stock, at average cost 393,222 392,011 Materials and supplies, at average cost 337,652 304,514 Vacation pay 69,394 61,907 Prepaid income taxes 51,101 61,104 Other 55,169 85,725 Total current assets 2,144,743 1,986,285 Property, Plant, and Equipment:

In service 22,011,215 21,279,792 Less accumulated provision for depreciation 8,696,668 8,343,309 13,314,547 12,936,483 Nuclear fuel, at amortized cost 198,983 180,129 Construction work in progress 1,797,642 923,948 Total property, plant, and equipment 15,311,172 14,040,560 Other Property and Investments:

Equity investments in unconsolidated subsidiaries 53,813 70,879 Nuclear decommissioning trusts, at fair value 588,952 544,013 Other 47,914 58,848 Total other property and investments 690,679 673,740 Deferred Charges and Other Assets:

Deferred charges related to income taxes 532,539 510,531 Prepaid pension costs 1,026,985 688,671 Deferred under recovered regulatory clause revenues 307,294 544,152 Other regulatory assets 541,014 629,003 Other 268,335 235,788 Total deferred charges and other assets 2,676,167 2,608,145 Total Assets $20,822,761 $19,308,730 The accompanying notes are an integral part of these financial statements.

30

B3ALANCE SHEETS At December 31, 2007 and 2006 Georgia Power Company 2007 Annual Report Liabilities and Stockholder's Equity 2007 2006 (in thousands)

Current Liabilities:

Securities due within one year $ 198,576 $ 303,906 Notes payable 715,591 733,281 Accounts payable -

Affiliated 236,332 238,093 Other 463,945 402,222 Customer deposits 171,553 155,763 Accrued taxes --

Income taxes 68,782 217,603 Other 219,585 275,098 Accrued interest 74,674 74,643 Accrued vacation pay 56,303 49,704 Accrued compensation 114,974 141,356 Other 103,225 125,494 Total current liabilities 2,423,540 2,717,163.

Long-term Debt (see accompanying statements) 5,937,792 5,211,912 Deferred Credits and Other Liabilities:

Accumulated deferred income taxes 2,850,655 2,815,724 Deferred credits related to income taxes 146,886 157,297 Accumulated deferred investment tax credits 269,125 282,070 Employee benefit obligations 678,826 698,274 Asset retirement obligations 663,503 626,681 Other cost of removal obligations 414,745 436,137 Other regulatory liabilities 577,642 281,391 Other 158,670 80,839 Total deferred credits and other liabilities 5,760,052 5,378,413 Total Liabilities 14,121,384 13,307,488 Preferred and Preference Stock (See accompanying statements) 265,957 44,991 Common Stockholder's Equity (See accompanying statements) 6,435,420 5,956,251 Total Liabilities and Stockholder's Equity $20,822,761 $19,308,730.

Commitments and Contingent Matters (See notes)

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

31

STATEMENTS OF CAPITALIZATION At December 31, 2007 and 2006 Georgia Power Company 2007 Annual Report 2007 2006 2007 2006 (in thousands) (percentof total)

Long-Term Debt:

Long-term debt payable to affiliated trusts --

4.88% to 7.13% due 2042 to 2044 $ 206,186 $ 969,073 Long-term notes payable --

4.875% due July 15, 2007 - 300,000 6.55% due May 15, 2008 45,000 45,000 4.10% due August 15, 2009 125,000 125,000 Variable rate (5.00% at 1/l/08) due 2008 150,000 Variable rate (5.09% at 1/1/08) due 2009 150,000 150,000 4.00% due 2011 100,000 100,000 5.125% due 2012 200,000 200,000 4.90% to 6.375% due 2013-2047 3,200,000 1,850,000 Total long-term notes payable 3,970,000 2,770,000 Other long-term debt --

Pollution control revenue bonds:

3.76% to 5.45% due 2012-2036 774,370 774,370 Variable rate (3.74% to 5.25% at 1/1/08) due 2011-2041 1,120,275 929,475 Total other long-term debt 1,894,645 1,703,845 Capitalized lease obligations 70,733 76,227 Unamortized debt discount (5,196) (3,327)

Total long-term debt (annual interest requirement -- $322.8 million) 6,136,368 5,515,818 Less amount due within one year 198,576 303,906 Long-term debt excluding amount due within one year 5,937,792 5,211,912 47.0% 46.5%

Preferred and Preference Stock:

Non-cumulative preferred stock

$25 par value -- 6.125%

Authorized - 50,000,000 shares Outstanding - 1,800,000 shares 44,991 44,991 Non-cumulative preference stock

$100 par value -- 6.50%

Authorized - 15,000,000 shares Outstanding - 2,250,000 shares 220,966 Total preferred and preference stock (annual dividend requirement -- $17.4 million) 265,957 44,991 2.1 0.4 Common Stockholder's Equity:

Common stock, without par value --

Authorized: 20,000,000 shares Outstanding: 9,261,500 shares 398,473 398,473 Paid-in capital 3,374,777 3,039,845 Retained earnings 2,676,063 2,529,826 Accumulated other comprehensive income (loss) (13,893) (11,893)

Total common stockholder's equity 6,435,420 5,956,251 50.9 53.1 Total Capitalization $12,639,169 $11,213,154 100.0% 100.0%

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

32

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2007, 2006, and 2005 Georgia Power Company 2007 Annual Report Other Common Paid-In Retained Comprehensive Stock Capital Earnings Income (Loss) Total (in thousands)

Balance at December 31, 2004 $398,473 $2,550,801 $2,211,042 $(37,040) $5,123,276 Net income after dividends on preferred stock - 744,373 - 744,373 Capital contributions from parent company - 166,738 - - 166,738 Other comprehensive income (loss) - 474 474 Cash dividends on common stock - (582;800) - (582,800)

Other - 22 22 Balance at December 31, 2005 398,473 2,717,539 2,372,637 (36,566) 5,452,083 Net income after dividends on preferred stock - - 787,225 787,225 Capital contributions from parent company - 322,306 - - 322,306 Other comprehensive income (loss) - 5,184 5,184 Adjustment to initially apply FASB Statement No. 158, net of tax - -. 19,489 19,489 Cash dividends on common stock - (630,000) (630,000)

Other - (36) (36)

Balance at December 31, 2006 398,473 3,039,845 2,529,826 (11,893) 5,956,251 Net income after dividends on preferred 836,136 836,136 and preference stock Capital contributions from parent company - 334,931 334,931 Other comprehensive income (loss) - (2,000) (2,000)

Cash dividends on common stock - (689,900) - (689,900)

Other 1 1 2 Balance at December 31, 2007 $398,473 $3,374,777 $2,676,063 $(13,893) $6,435,420 The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2007, 2006, and 2005 Georgia Power Company 2007 Annual Report 2007 2006 2005 (in thousands)

Net income after dividends on preferred and preference stock $836,136 $787,225 $744,373 Other comprehensive income (loss):

Qualifying hedges:

Changes in fair value, net of tax of $(1,831), $(935),

and $1,522, respectively (2,938) (1,454) 2,420 Reclassification adjustment for amounts included in net income, net of tax of $278, $(441), and $861, respectively 441 (700) 1,065 Marketable securities:

Changes in fair value, net of tax of $291, $(494),

and $317, respectively 497 (817) 501 Pension and other postretirement benefit plans:

Change in additional minimum pension liability, net of tax of $-, $5,143, and $(2,216), respectively 8,155 (3,512)

Total other comprehensive income (loss) (2,000) 5,184 474 Comprehensive Income $834,136 $792,409 $744,847 The accompanying notes are an integral part of these financial statements.

33

NOTES TO FINANCIAL STATEMENTS Georgia Power Company 2007 Annual Report

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES General Georgia Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies -

Alabama Power, the Company, Gulf Power, and Mississippi Power - provide electric service in four Southeastern states. 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. Southern Power constructs, acquires, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company's nuclear power plants.

The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary.

The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Georgia Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

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

These reclassifications had no effect on total assets, net income, or cash flows.

The balance sheets and the statements of cash flows have been modified to combine "Long-term Debt Payable to Affiliate Trusts" with "Long-term Debt." Correspondingly, the statements of income were modified to report "Interest expense to affiliate trusts" together with "Interest expense, net of amounts capitalized". The balance sheets were also modified to show a separate line item for "Prepaid Income Taxes", the amount of which was included in "Prepaid Expenses" in the previous year's presentation. Due to immateriality, the statements of cash flows were also modified by combining "Deferred expenses-affiliates" with "Other, net" within the operating activities section.

Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost:

general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $442 million in 2007, $386 million in 2006, and $348 million in 2005. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $380 million in 2007,

$348 million in 2006, and $328 million in 2005.

34

NOTES (continued)

Georgia Power Company 2007 Annual Report The Company had an agreement with Southern Power under which the Company operated and maintained Southern Power's Plants Dahlberg, Franklin, and Wansley at cost. On August 1, 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern Power labor and other specifically requested services. Billings under these agreementswith Southern Power amounted to $6.8 million in 2007, $5.4 million in 2006, and $5.2 million in 2005.

The Company has an agreement with SouthernLlNC Wireless under which the Company receives digital wireless communications services and purchases digital equipment. Costs for these services amounted to $7.0 million in 2007, $7.1 million in 2006, and

$7.7 million in 2005.

Southern Company's 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produced synthetic fuel, was terminated July 1, 2006. The Company had an agreement with an indirect subsidiary of Southern Company that provided services for AFP.

Under this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $85 million in 2007, $76 million in 2006, and $61 million in 2005. In addition, the Company purchased synthetic fuel from AFP for use at Plant Branch. Synthetic fuel purchases totaled $179 million, $195 million, and $216 million in 2007, 2006, and 2005, respectively. The synthetic fuel purchases and related party transactions were terminated as of December 31, 2007.

The Company has entered into several power purchase agreements (PPAs) with Southern Power for capacity and energy. Expenses associated with these PPAs were $440 million, $407 million, and $469 million in 2007, 2006, and 2005, respectively. Additionally, the Company had $26 million and $28 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2007, and 2006, respectively. See Note 7 under "Purchased Power Commitments" for additional information.

The Company has an agreement with Gulf Power under which Gulf Power jointly owns a portion of Plant Scherer. Under this agreement, the Company operates Plant Scherer, and Gulf Power reimburses the Company for its proportionate share of the related expenses which were $5.1 million in 2007, $8.0 million in 2006, and $4.3 million in 2005. See Note 4 for additional information.

In 2007, the Company sold equipment at cost to Gulf Power for $4.0 million.

The Company provides incidental services to other Southern Company subsidiaries which are generally minor in duration and amount.

However, with the hurricane damage experienced by Alabama Power, Gulf Power, and Mississippi Power in 2005, assistance provided to aid in storm restoration, including company labor, contract labor, and materials, caused an increase in these activities. The total amount of storm assistance provided to Alabama Power, Gulf Power, and Mississippi Power in 2005 was $4.3 million,

$5.0 million, and $55.2 million, respectively. These activities were billed at cost. The Company provided no significant storm assistance to an affiliate in 2007 and 2006.

Also see Note 4 for information regarding the Company's ownership in and PPA with Southern Electric Generating Company (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates.

The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel Commitments" for additional information.

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

35

NOTES (continued)

Georgia Power Company 2007 Annual Report Regulatory assets and (liabilities) reflected in the Company's balance sheets at December 31 relate to the following:

2007 2006 Note (in millions)

Deferred income tax charges $ 533 $511 (a)

Loss on reacquired debt 175 171 (b)

Vacation pay 69 62 (c)

Corporate building lease 49 51 (d)

Generating plant outage costs 44 56 (e)

Underfunded retiree benefit plans 235 310 (0)

Fuel-hedging assets 14 58 (g)

Other regulatory assets 68 42 (d)

Asset retirement obligations 41 53 (a)

Other cost of removal obligations (415) (436) (a)

Deferred income tax credits (147) (157) (a)

Overfunded retiree benefit plans (540) (218) (f)

Fuel-hedging liabilities (9) (6) (g)

Other regulatory liabilities (12) (39) (d)

Total $ 105 $458 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(a) Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 60 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.

(b) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue which may range up to 50 years.

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

(d) Recorded and recovered or amortized as approved by the Georgia PSC.

(e) See "Property, Plant, and Equipment" herein.

(f) Recovered and amortized over the average remaining service.period which may range up to 16 years, See Note 2 under "Retirement Benefits."

(g) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed 42 months. Upon final settlement, costs are recovered through the fuel cost recovery clause.

In the event that a portion of the Company's operations is no longer subject to the provisions of SFAS 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 write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are reflected in rates.

Revenues Energy and other revenues are recognized as services are provided. Unbilled revenues are accrued at the end of each fiscal period.

Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs and the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.

Retail fuel cost recovery rates require periodic filings with the Georgia PSC. The Company is required to file its next fuel case by 36

NOTES (continued)

Georgia Power Company 2007 Annual Report March 1, 2008. See Note 3 under "Retail Regulatory Matters-- Fuel Cost Recovery."

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

Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.

Nuclear Fuel Disposal Costs The Company has contracts with the United States, acting through the U.S. Department of Energy (DOE), that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and the Company is pursuing legal remedies against the government for breach of contract.

On July 9, 2007, the U.S. Court of Federal Claims awarded the Company $30 million, based on its ownership interests, representing all of the direct costs of the expansion of spent nuclear fuel storage facilities from 1998 through 2004. On July 24, 2007, the government filed a motion for reconsideration, which was denied on November 1, 2007. The government filed an appeal on January 2, 2008. No amounts have been recognized in the financial statements as of December 31, 2007. The final outcome of this matter cannot be determined at this time, but no material impact on net income is expected as any award received is expected to be returned to customers.

Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plant Hatch, an on-site dry storage facility is operational and can be expanded to accommodate spent fuel through the expected life of the plant.

Property, Plant, and Equipment Property, plant, and equipment is stated at original cost, less regulatory disallowances and impairments. Original cost includes:

materials; labor; minor items of property; appropriate administrative and general costs; payroll- related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.

The Company's property, plant, and equipment consisted of the following at December 3 1:

2007 2006 (in millions)

Generation $10,180 $10,064 Transmission 3,593 3,331 Distribution 6,985 6,652 General 1,225 1,205 Plant acquisition adjustment 28 28 Total plant in service $22,011 $21,280 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by a Georgia PSC order, the Company defers and amortizes nuclear refueling costs over the unit's operating cycle before the next refueling. The refueling cycles are 18 and 24 months for Plants Vogtle and Hatch, 37

NOTES (continued)

Georgia Power Company 2007 Annual Report respectively. Also, in accordance with the Georgia PSC order, the Company defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle.

Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" (FIN 48), the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information on the effect of adopting FIN 48.

Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.6% in each of 2007, 2006, and 2005. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC. Effective January 1, 2008, the Company's depreciation. rates were revised by the Georgia PSC.

When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

Under the Company's retail rate plan for the three years ended December 31, 2007 (2004 Retail Rate Plan), the Company was ordered to recognize Georgia PSC-certified capacity costs in rates evenly over the three years covered by the 2004 Retail Rate Plan. The Company recorded credits to amortization of $19 million and $14 million in 2007 and 2006, respectively, and an increase to amortization of $33 million in 2005. See Note 3 under "Retail Regulatory Matters - Rate Plans" for additional information.

Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.

The liability recognized to retire long-lived assets primarily relates to the Company's nuclear facilities, which include the Company's ownership interests in Plants Hatch and Vogtle. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2007 was $589 million. In addition, the Company has retirement obligations related to various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, leasehold improvements, equipment on customer property, and property associated with the Company's rail lines. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income the allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under FASB Statement No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143) and FASB Interpretation No. 47, "Conditional Asset Retirement Obligations" and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See "Nuclear Decommissioning" herein for further information on amounts included in rates.

38

NOTES (continued)

Georgia Power Company 2007 Annual Report Details of the asset retirement obligations included in the balance sheets are as follows:

2007 2006 (in millions)

Balance beginning of year $ 627 $635 Liabilities incurred - 5 Liabilities settled (3) (2)

Accretion 40 41 Cash flow revisions - (52)

Balance end of year $ 664. $627 Nuclear Decommissioning The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds to comply with the NRC's regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Georgia PSC, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale.

The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. As the external trust funds are actively managed by unrelated parties with limited direction from the Company, the Company does not have the ability to choose to hold securities with unrealized losses until recovery. Through 2005, the Company considered other-than-temporary impairments to be immaterial. However, since the January 1, 2006 effective date of FASB Staff Position FAS 115-1/124-1, "The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments" (FSP No. 115-1), the Company considers all unrealized losses to represent other-than-temporary impairments. The adoption of FSP No. 115-1 had no impact on the results of operations, cash flows, or financial condition of the Company as all losses have been and continue to be recorded through a regulatory liability, whether realized, unrealized, or identified as other-than-temporary.

Details of the securities held in these trusts at December 31, 2007 were as follows:

Other-than-Temporary 2007 Unrealized Gains Impairments Fair Value (in millions)

Equity $ 125.5 $ (12.2) $ 402.4 Debt 4.8 (1.8) 171.8 Other - 14.8 Total $ 130.3 $ (14.0) $ 589.0 Other-than-Temporary Fair Value 2006 Unrealized Gains Impairments (in millions)

Equity $ 106.9 $ (5.0) $ 378.3 Debt 3.0 (0.7) 165.4 Other - 0.3 Total 109.9 $ (5.7) $ 544.0 The contractual maturities of debt securities at December 31, 2007 were as follows: $2.6 million in 2008, $38.5 million in 2009-2012,

$41.1 million in 2013-2017, and $85.4 million thereafter.

Sales of the securities held in the trust funds resulted in cash proceeds of $441.4 million, $457.4 million, and $372.5 million in 2007, 2006, and 2005, respectively, all of which were re-invested. Realized gains and other-than-temporary impairment losses were

$43.7 million and $39.1 million, respectively, in 2007 and $17.8 million and $12.1 million, respectively, in 2006. Net realized 39

NOTES (continued)

Georgia Power Company 2007 Annual Report gains/(losses) were $12.6 million in 2005. Realized gainsand other-than-temporary impairment losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income.

Unrealized gains and other-than-temporary impairment losses are considered non-cash transactions for purposes of the statements of cash flows. Unrealized losses were not material in any period presented and did not require the recognition of any impairment to the underlying investments.

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

Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning are based on the most current study performed in 2006. The site study costs and accumulated provisions for decommissioning as of December 31, 2007 based on the Company's ownership interests were as follows:

Plant Hatch Plant Vogtle Decommissioning periods:

Beginning year 2034 2027 Completion year 2061 2051 Site study costs: (in millions)

Radiated structures $ 544 $ 507 Non-radiated structures 46 67 Total'site study costs $ 590 $ 574 Accumulated provision $ 368 $ 222 The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities. The Georgia PSC approved annual decommissioning costs for ratemaking were $7 million annually for Plant Vogtle for 2005.through 2007. Under the 2007 Retail Rate Plan, the annual decommissioning cost for ratemaking will decrease to $3 million for Plant Vogtle. Based on current estimates, the Company projects the external trust funds for Plant Hatch will be adequate to meet the decommissioning obligations with no further contributions. The NRC estimates are $450 million and

$313 million for Plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.9% and an estimated trust earnings rate of 4.9%. Another significant assumption was that the operating licenses for Plant Vogtle, would remain at 40 years until a 20-year extension requested by the Company in June 2007 is authorized by the NRC. The Company anticipates the NRC may make a decision regarding the license extension for Plant Vogtle as early as 2009.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The equity component of AFUDC is not included in calculating taxable income. For the years 2007, 2006, and 2005, the average AFUDC rates were 8.4%, 8.3%, and 8.0%, respectively, and AFUDC capitalized was $96.8 million, $44.1 million, and

$41.1 million, respectively. AFUDC and interest capitalized, net of taxes were 10.3%, 5.0%, and 4.9% of net income after dividends on preferred and preference stock for 2007, 2006, and 2005, respectively.

40

NOTES (continued)

Georgia Power Company 2007 Annual Report Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when,0vents or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating thefair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. -Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Storm Damage Reserve The Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated by the Georgia PSC.

Under the 2004 Retail Rate Plan, the Company accrued $6.6 million annually that was recoverable through base rates. Starting January 1, 2008, the Company will accrue $21.4 million annually under the 2007 Retail Rate Plan. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs.

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

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

Fuel Inventory Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC.

Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Stock Options Southern Company provides non-qualified stock options to a large segment, of the Company's employees ranging from line management to executives. Prior to January 1; 2006, the Company accounted for options granted in accordance with Accounting Principles Board Opinion No. 25; thus, no compensation expense was recognized because the exercise price of all options granted equaled the fair market value on the date of the grant.

Effective January 1,2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), "Share-Based Payment" (SFAS No. 123(R)), using the modified prospective method. Under that method, compensation cost for the years-ended December 31, 2007 and 2006 was recognized as the requisite service wasrendered and included: (a) compensation cost forthe portion of share-based awards granted prior to and that were outstanding as of January 1, 2006, for which the requisite service had not been rendered, based on the grant-date fair value of those awards as calculated in accordance with the original provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation", and (b) compensation cost. for all share-based awards granted subsequent to January 1,2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R).

Results for prior periods have not been restated.

The compensation cost'and tax benefits related to the grant and exercise of Southern Company stock options to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.

41

NOTES (continued)

Georgia Power Company 2007 Annual Report For the Company, the adoption of SFAS No. 123(R) resulted in a reduction in earnings before income taxes and net income of $6.0 million and $3.7 million, respectively, for the year ended December 31, 2007, and $5.8 million and $3.6 million, respectively, for the year ended December 31, 2006. Additionally, SFAS No. 123(R) requires the gross excess tax benefits from stock option exercises to be reclassified as a financing cash flow as opposed to an operating cash flow; the reduction in operating cash flows and the increase in financing cash flows for the years ended December 31, 2007 and December 31, 2006 was $4.7 million and $2.8 million, respectively.

For the year ended December 31, 2005, prior to the adoption of SFAS No. 123(R), the pro forma impact on net income of fair-value accounting for options granted was as follows:

Options Impact 2005 As Reported After Tax Pro Forma (in millions)

Net income $ 744 $ (3) $ 741 Because historical forfeitures have been insignificant and are expected to remain insignificant, no forfeitures were assumed in the calculation of compensation expense; rather they are recognized when they occur.

The estimated fair values of stock options granted in 2007, 2006, and 2005 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term.

The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: I Year Ended December 31 2007 2006 2005 Expected volatility 14.8% 16.9% 17.9%

Expected term (inyears) 5.0 5.0 5.0 Interest rate 4.6% 4.6% 3.9%

Dividend yield 4.3% 4.4% 4.4%

Weighted average grant-date fair value $ 4.12 $ 4.15 $ 3.90 Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.

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

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

Carrying Amount Fair Value (in millions)

Long-term debt:

2007 $ 6,066 $ 5,969 2006 $ 5,440 $ 5,376 42

NOTES (continued)

Georgia Power Company 2007 Annual Report The fair values were based on either closing market prices or closing prices of comparable instruments.

Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and prior to the adoption of SFAS No. 158,.

"Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans" (SFAS No. 158) the minimum pension liability, less income taxes and reclassifications for amounts included in net income.

Variable Interest Entities The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. However, the Company is not considered the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt in the balance sheets. See Note 6 under "Long-Term Debt Payable to Affiliated Trusts" for additional information.

2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2008. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds related trusts to the extent required by the FERC. For the year ending December 31, 2008, postretirement trust contributions are expected to total approximately $23.0 million.

The measurement date for plan assets and obligations is September 30 for each year presented. Pursuant to SFAS No. 158, the Company will be required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ending December 31, 2008.

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NOTES (continued)

Georgia Power Company 2007 Annual Report Pension Plans The total accumulated benefit obligation for the pension plans was $2.0 billion in 2007 and $2.0 billion in 2006. Changes during the year in the projected benefit obligations and the fair value of plan assets were as follows:

2007 2006 (in millions)

Change in benefit obligation Benefit obligation at beginning of year $ 2,136 $2,172 Service cost 51 53 Interest cost 126 117 Benefits paid (98) (95)

Plan amendments 15 2 Actuarial (gain) loss (52) (113)

Balance at end of year 2,178 2,136 Change in plan assets Fair value of plan assets at beginning of year 2,710 2,493 Actual return on plan assets 456 306 Employer contributions 5 6 Benefits paid (98) (95)

Fair value of plan assets at end of year 3,073 2,710 Funded status at end of year 895 574 Fourth quarter contributions 2 2 Prepaid pension asset, net $ 897 $ 576 At December 31, 2007, the projected benefit obligations for the qualified and non-qualified pension plans were $2.0 billion and $133 million, respectively. All plan assets are related to the qualified pension plan.

Pension plan assets are managed and invested i*naccordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company's pension plan assets as of the end of the year, along with the targeted mix of assets, is presented below:

Target 2007 2006 Domestic equity 36% 38% 38%

International equity 24 24 23 Fixed income 15 15 16 Real estate 15 16 16 Private equity 10 7 7 Total 100% __100% 100%

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NOTES (continued)

Georgia Power Company 2007 Annual Report Amounts recognized in the balance sheets related to the Company's pension plans consist of the following:

2007 2006 (in millions)

Prepaid pension costs $ 1,027 $689 Other regulatory assets 64 56 Current liabilities, other (7) (6)

Other regulatory liabilities (540) (218)

Employee benefit obligations (123) (107)

Presented below are the amounts included in regulatory assets and regulatory liabilities at December 31, 2007 and 2006 related to the defined benefit pension plans that have not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2008.

Prior Service Cost Net(Gain)ILoss Balance at December 31, 2007: (in millions)

Regulatory asset $ 24 $ 40 Regulatory liabilities 81 (621)

Total $105 $ (581)

Balance at December 31, 2006: (in millions)

Regulatory asset $ 11 $45 Regulatory liabilities 92 (310)

Total $ 103 $(265)

Estimated amortization in net periodic pension cost in 2008: (in millions)

Regulatory assets $ 3 $ 3 Regulatory liabilities 1II Total $ 1.4 $ 3 The changes in the balances of regulatory assets and regulatory liab ilities related to the defined benefit pension plans for the year ended December 31, 2007 are presented in the following table:

Regulatory Assets Regulatory Liabilities (in millions).

Beginning balance $ 56 $ (218)

Net gain (1) (311)

Change in prior service costs 15 Reclassification adjustments:

Amortization of prior service costs (3) (11)

Amortization of net gain (3).

Total reclassification adjustments (6) (1 Total change 8 (322)

Ending balance $ 64 $ (540) 45

NOTES (continued)

Georgia Power Company 2007 Annual Report Components of net periodic pension cost (income) were as follows:

2007 2006 2005 (in millions)

Service cost $ 51 $ 53 $ 47 Interest cost 126 117 112 Expected return on plan assets (195) (184) (186)

Recognized net (gain) loss 3 6 4 Net amortization 14 8 9 Net periodic pension cost (income) $ (1) $ - $(14)

Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2007, estimated benefit payments were as follows:

Benefit Payments (in millions) 2008 $ 110 2009 115 2010 119 2011 134 2012 142 2013 to2017 $ 682 46

NOTES (continued)

Georgia Power Company 2007 Annual Report Other Postretirement Benefits Changes during the year in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:

2007 2006 (in millions)

Change in benefit obligation Benefit obligation at beginning of year $ 807 $ 812 Service cost 10 11 Interest cost 47 43 Benefits paid (35) (34)

Actuarial (gain) loss (33) (27)

Retiree drug subsidy 2 2 Balance at end of year 798 807 Change in plan assets Fair value of plan assets at beginning of year 388 362 Actual return on plan assets 54 35 Employer contributions 18 48 Benefits paid (33) (57)

Fair value of plan assets at end of year 427 388 Funded status at end of year (371) (419)

Fourth quarter contributions 31 20 Accrued liability (recognized in the balance sheets) $ (340) $ (399)

Other postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company's other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:

Target 2007 2006 Domestic equity 43% 46% 44%

International equity 21 23 20 Fixed income 29 25 27 Real estate 4 4 6 Private equity 3 2 3 Total 100% 100% 100%

Amounts recognized in the balance sheets related to the Company's other postretirement benefit plans consist of the following:

2007 2006 (in millions)

Other regulatory assets $ 171 $ 255 Employee benefit obligations (340) (399) 47

NOTES (continued)

Georgia Power Company 2007 Annual Report Presented below are the amounts included in regulatory assets at December 31, 2007 and 2006 related to the other postretirement benefit plans that have not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2008:

Prior Service Net Transition Cost (Gain)/Loss Obligation (in millions)

Balance at December 31, 2007:

Regulatory assets $ 22 $ 94 $ 55 Balance at December 31, 2006:

Regulatory assets $ 24 $ 166 $ 64 Estimated amortization in net periodic postretirement benefit cost in 2008:

Regulatory assets $ 2 $ 5 $ 9 The change in the balance of regulatory assets related to the other postretirement benefit plans for the year ended December 31, 2007 is presented in the following table:

Regulatory Assets (in millions)

Beginning balance $ 254 Net gain (64)

Change in prior service costs Reclassification adjustments:

Amortization of transition obligation (9)

Amortization of prior service costs (2)

' Amortization of net gain (8)

Total reclassification adjustments (19)

Total change (83)

Endina balance $ 171 Components of the other postretirement benefit plans' net periodic cost were as follows:

2007 2006 2005 (in millions)

Service cost $ 10 $ I1 $11 Interest cost 47 44 43 Expected return on plan assets (26) (25) (23)

Net amortization 19 22 19 Net postretirement cost $ 50 $ 52 $ 50 The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company's expenses for the years ended December 31, 2007, 2006, and 2005 by approximately $14 million, $16 million, and $11 million, respectively.

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NOTES (continued)

Georgia Power Company 2007 Annual Report Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

Benefit Payments Subsidy Receipts Total (in millions) 2008 $ 43 $ (3) $ 40 2009 46 (4) 42 2010 51 (4) 47 2011 55 (5) 50 2012 58 (5) 53 2013to2017 $ 331 $ (37) $ 294 Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2004 for the 2005 plan year using a discount rate of 5.75%.

2007 2006 2005 Discount 6.30% 6.00% 5.50%

Annual salary increase 3.75 3.50 3.00 Long-term return on plan assets 8.50 8.50 8.50 The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.75% for 2008, decreasing gradually to 5.25% through the year 2015, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2007 as follows:

1 Percent 1 Percent Increase Decrease (in millions)

Benefit obligation $ 62 $ 53 Service and interest costs $ 5 $ 4 Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85%

matching contribution up to 6% of an employee's base salary. Prior to November 2006, the.Company matched employee contributions at a rate of 75% up to 6% of the employee's base salary. Total matching contributions made to the plan for 2007, 2006, and 2005 were $24 million, $21 million, and $20 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout 49

NOTES (continued)

Georgia Power Company 2007 Annual Report the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company's financial statements.

Environmental Matters New Source Review Actions In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities, including the Company's Plants Bowen and Scherer. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government's claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power's motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA's claims related to the remaining four plants.

The plaintiffs appealed the district court's decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court's decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court's Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court's decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court's decision in the Duke Energy case.

The Company believes it has complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation In July 2004, attorneys general from eight states, each outside of the Company's service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company, including the Company, and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies' emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. The Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis .for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company's and the other defendants' motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.

50

NOTES (continued)

Georgia Power Company 2007 Annual Report EnvironmentalRemediation Through 2007, the Company recovered environmental costs through its base rates. Beginning in 2005, such rates included an annual accrual of $5.4 million for environmental remediation. Beginning in January 2008, the Company is recovering environmental remediation costs through a new tariff (see "Rate Plans" herein) that includes an annual accrual of $1.2 million for environmental remediation. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings. Under Georgia PSC ratemaking provisions, $22 million had previously been deferred in a regulatory liability account for use in meeting future environmental remediation costs of the Company and was amortized over a three-year period that ended December 31, 2007. As of December 31, 2007, the balance of the environmental remediation liability was $13.5 million.

The Company has been designated as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated.

The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the Company's financial statements.

FERC Matters Market-BasedRate Authority The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

In December 2004, the FERC initiated a proceeding to assess Southern Company's generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company's retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.

In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates and could also result in refunds of up to $5.8 million, plus interest.

The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.

On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.

IntercompanyInterchange Contract The Company's generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the I1C among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC's standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company's code of conduct defining Southern Power as a "system company" rather than a "marketing affiliate" is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power's inclusion in the IIC in 2000. The FERC also previously approved Southern Company's code of conduct.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company's agreement to accept certain modifications to the settlement's terms and Southern Company notified the FERC that it accepted the modifications.

51

NOTES (continued)

Georgia Power Company 2007 Annual Report The modifications largely, involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company's financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.

Generation InterconnectionAgreements In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.

On January 19, 2007, the FERC issued an order granting Tenaska's requested relief. Although the FERC's order required the modification of Tenaska's interconnection agreements, under the provisions of the order the Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC's methodology for determining the amount of refunds. The requested rehearings were denied and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.

Right of Way Litigation In late 2001, certain subsidiaries of Southern Company, including Alabama Power, the Company, Gulf Power, Mississippi Power, and Southern Telecom, Inc. (a subsidiary of SouthemLfNC Wireless), were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants' rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff s claims are.

without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company's appeal of the trial court's order for lack of jurisdiction. 'An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company could result in substantial judgments; however, the final outcome cannot now be determined.

Income Tax Matters The Company's 2005 through 2007 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. The Company has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. On July 24, 2007, the Company filed a complaint in the, Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. If the Company prevails, these claims could have a significant, and possibly material, positive effect on the Company's net income. If the Company is rior'successful, payment of the related state tax could have a significant, and possibly material, negative effect on the Company's cash flow. The ultimate outcome of thismatter cannot now be determined. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Property Tax Matters The Monroe County Board of Tax Assessors (Monroe Board) had issued assessments reflecting substantial increases in the ad valorem tax valuation of the Company's 22.95% ownership interest in Plant Scherer, which is located in Monroe County, Georgia (Monroe County) for tax years 2003 through 2007.

In November 2004, the Company filed suit against the Monroe Board in the Superior Court of Monroe County. The Company requested injunctive relief prohibiting Monroe County and the Monroe Board from unlawfully changing the value of Plant Scherer and ultimately collecting additional ad Valorem taxes from the Company. In December 2005, the court granted Monroe County's motion for summary judgment. The Company filed an appeal of the Superior Court's decision to the Georgia Supreme Court.

52

NOTES (continued)

Georgia Power Company 2007 Annual Report On March 30, 2007, the Georgia Court of Appeals reversed the trial court and ruled that the Monroe Board had exceeded its legal authority and remanded the case for entry. of an injunction prohibiting the Monroe Board from collecting taxes based on its independent valuation of Plant Scherer. On July 16, 2007, the Georgia Supreme Court agreed to hear the Monroe Board's requested review of this decision. On January 9, 2008, the Georgia Supreme Court upheld the appeals court decision. This litigation is now concluded.

Retail Regulatory Matters Merger Effective July 1, 2006, Savannah Electric, which was also a wholly owned subsidiary of Southern Company, was merged into the Company. The Company has accounted for the merger in a manner similar to a pooling of interests, and the Company's financial statements included herein now reflect the merger as though it had occurred on January 1, 2004.

Rate Plans In December 2004, the Georgia PSC approved the 2004 Retail Rate Plan for the Company. Under the terms of the 2004 Retail Rate Plan, the Company's earnings were evaluated against a retail return on equity (ROE) range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% were applied to rate refunds, with the remaining one-third retained by the Company. Retail rates and customer fees increased by approximately $203 million effective January 1, 2005 to cover the higher costs of purchased power, operating and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. In 2007, the Company refunded 2005 earnings above 12.25% retail ROE. There were no refunds related to earnings for the years 2006 and 2007.

In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan for the years 2008 through 2010. Retail base rates increased by approximately $99.7 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investment, as well as increased operating costs. In addition, the new environmental compliance cost recovery (ECCR) tariff was implemented to recover costs incurred for environmental projects required by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008. Under the 2007 Retail Rate Plan, the Company's earnings will continue to be evaluated against a retail ROE range of 10.25% to 12.25%. Two thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to the ECCR tariff. The Company agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%.

The Company is required to file a general rate case by July 1, 20 10, in response to which the Georgia PSC would be expected to determnine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued.

Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Georgia PSC. In May 2005, the Georgia PSC approved the Company's request to increase customer fuel rates by approximately 9.5% to recover under recovered fuel costs of approximately

$508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005.

In November 2005, the Georgia PSC voted to approve Savannah Electric's request to increase customer rates to recover estimated under recovered fuel costs of approximately $71.8 million as of November 30, 2005 over an estimated four-year period beginning December 1, 2005, as well as future projected fuel costs.

In March 2006, the Company and Savannah Electric filed a combined request for fuel cost recovery rate changes with the Georgia PSC to be effective July 1, 2006, concurrent with the merger of the companies. In June 2006, the Georgia PSC ruled on the request and approved an increase in the Company's total annual fuel billings of approximately $400 million. The Georgia PSC order provided for a combined ongoing fuel forecast but reduced the requested increase related to such forecast by $200 million. The Georgia PSC also set a merger transition adjustment (MTA) applicable to customers in the former Savannah Electric service territory so that the fuel rate that became effective on July 1, 2006 plus th'eMTA equaled the applicable fuel rat .e paid by such customers as of June 30, 2006.

Amounts collected under the NITA were being credited to customers in the original Georgia Power service territory through a merger transition credit through December 31, 2007. The order also required the Company to file for a new fuel cost recovery rate on a semi-annual basis, beginning in September 2006. Accordingly, on September 15, 2006, the Company filed a request to recover fuel costs incurred through August 2006 by increasing the fuel cost recovery rate. On November 13, 2006, under agreement with the Georgia 53

NOTES (continued)

Georgia Power Company 2007 Annual Report PSC staff, the Company filed a supplementary request reflecting a forecast of annual fuel costs, as well as updated information for previously incurred fuel costs.

On February 6, 2007, the Georgia PSC approved an increase in the Company's total annual billings of approximately $383 million effective March 1,2007. The Georgia PSC order reduced the Company's requested increase in the forecast of annual fuel costs by

$40 million and disallowed $4 million of previously incurred fuel costs. Estimated under recovered fuel costs through February 2007 are being recovered through May 2009 for customers in the original Georgia Power territory and through November 2009 for customers in the former Savannah Electric territory. On December 31, 2006, the Company had an under recovered fuel balance of approximately $898 million, of which approximately $544 million was included in deferred charges and other assets in the balance sheets. As of December 31, 2007, the Company had an under recovered fuel balance of approximately $692 million, of which approximately $307 million is included in deferred charges and other assets in the balance sheets. The order also requires the Company to file for a new fuel cost recovery rate no later than March 1, 2008.

FuellHedgingProgram The Georgia PSC has approved a natural gas, oil procurement, and hedging program that allows the Company to use financial instruments to hedge price and commodity risk associated with these fuels, subject to certain limits in terms of time, volume, dollars, and physical amounts hedged. The costs of the program, including any net losses, are recovered as a fuel cost through the fuel cost recovery clause. Annual net financial gains from the hedging program, through June 30, 2006, were shared with the retail customers receiving 75% and the Company retaining 25% of the total net gains. Effective July 1, 2006, the profit sharing framework related to the fuel hedging program was terminated. In 2005, the Company had a total net gain of $74.6 million, of which the Company retained

$18.6 million. The Company realized net losses in 2006 and 2007 of $66 million and $68 million, respectively.

NuclearProject Cost Deferral In June 2006, the Georgia PSC approved the Company's request to defer for future recovery the early site permit and combined construction and operating license costs, of which the Company's portion is estimated to total approximately $51 million. At December 31, 2007, approximately $28.4 million is included in deferred charges and other assets. At this point, no final decision has been made regarding actual construction. Any new generation resource must be certified by the Georgia PSC in a separate proceeding.

4. JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of the units has been sold equally to the Company and Alabama Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, debt service, and return on investment, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party's right to cancel upon two year's notice.

The Company's share of expenses included in purchased power from affiliates in the statements of income is as follows:

2007 2006 2005 (in millions)

Energy $ 66 $ 58 $ 54 Capacity 42 38 38 Total $108 $ 96 $ 92 The Company owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG), the city of Dalton, Georgia, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company and Progress Energy Florida, Inc. jointly own a combustion turbine unit (Intercession City) operated by Progress Energy Florida, Inc.

54

NOTES (continued)

Georgia Power Company 2007 Annual Report At December 31, 2007 the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation were as follows:

Company Accumulated Facility (Type) Ownership Investment Depreciation (in millions)

Plant Vogtle (nuclear) 45.7% $ 3,288 $ 1,900 Plant Hatch (nuclear) 50.1 938 509 Plant Wansley (coal) 53.5 406 185 Plant Scherer (coal)

Units I and 2 8.4 116 64 Unit 3 75.0 566 309 Rocky Mountain (pumped storage) 25.4 170 99 Intercession City (combustion-turbine) 33.3 12 3 At December 31, 2007, the portion of total construction work in progress related to Plants Wansley, Scherer, and Rocky Mountain was

$170.3 million, $66.5 million, and $4.0 million, respectively, primarily for environmental projects.

The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income.

5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

Current and Deferred Income Taxes The transfer of the Plant McIntosh construction project from Southern Power to the Company in 2005 resulted in a deferred gain to Southern Power for federal income tax purposes. The Company is reimbursing Southern Power for the remaining balance of the related deferred taxes of $4.6 million as it is reflected in Southern Power's future taxable income. $4.1 million of this payable to Southern Power is included in Other Deferred Credits and $0.5 million is included in Affiliated Accounts Payable in the balance sheets at December 31, 2007.

The transfer of the Dahlberg, Wansley, and Franklin projects to Southern Power from the Company in 2001 and 2002 also resulted in a deferred gain for federal income tax purposes. Southern Power is reimbursing the Company for the remaining balance of the related deferred taxes of $9.5 million as it is reflected in the Company's future taxable income. $7.7 million of this receivable from Southern Power is included in Other Deferred Debits and $1.8 million is included in Affiliated Accounts Receivable in the balance sheets at December 31, 2007.

55

NOTES (continued)

Georgia Power Company 2007 Annual Report Details of income tax provisions are as follows:

2007 2006 2005 (in millions)

Federal -

Current $442 $393 $ 166 Deferred (72) 7 226_

370 400 392 State -

Current 54 33 24 Deferred (6) 9 32 Deferred investment tax credits - - -

48 42 56 Total $418 $442 $ 448 The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

2007 2006 (in millions)

Deferred tax liabilities -

Accelerated depreciation $ 2,376 $ 2,303 Property basis differences 568 568 Employee benefit obligations 374 243 Fuel clause under recovery 281 365 Premium on reacquired debt 71 69 Regulatory assets associated with employee benefit obligations 123 156 Asset retirement obligations 257 242 Other 53 75 Total 4,103 4,021 Deferred tax assets -

Federal effect of state deferred taxes 160 123 Employee benefit obligations 226 226 Other property basis differences 130 138 Other deferred costs 131 131 Other comprehensive income 2 9 Regulatory liabilities associated with employee benefit obligations 209 84 Unbilled fuel revenue 34 27 Asset retirement obligations 257 242 Other 35 41 Total 1,184 1,021 Total deferred tax liabilities, net 2,919 3,000 Portion included in current liabilities, net (69) (185)

Accumulated deferred income taxes in the balance sheets $ 2,850 $2,815 At December 31, 2007, tax-related regulatory assets were $533 million and tax-related regulatory liabilities were $147 million. The assets are attributable to tax benefits flowed through to customers, in prior years and to taxes applicable to capitalized interest. The liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.

56

NOTES (continued)

Georgia Power Company 2007 Annual Report In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $13.0 million annually in 2007, 2006, and 2005. At December 31, 2007, all investment tax credits available to reduce federal income taxes payable had been utilized.

Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate was as follows:

2007 2006 2005 Federal statutory rate 35.0% 35.0% 35.0%.

State income tax, net of federal deduction 2.4 2.2 3.1 Non-deductible book depreciation 1.1 1.1 1.2 AFUDC Equity (1.9) (0.9) (0.9)

Donations (1.7) - -

Other (1.7) (1.6) (0.9)

Effective income tax rate 33.2% 35.8% 37.5%

The decrease in 2007's effective tax rate is the result of the tax benefits associated with donations and an increase in state tax credits and the federal manufacturer's tax deduction.

In 2007, the Company donated 2,200 acres of land in the Tallulah Gorge State Park to the State of Georgia. The estimated value of this donation along with an increase in non-taxable AFUDC equity and available state tax credits as well as higher federal tax deductions caused a lower effective income tax rate for the year ended 2007, when compared to prior years. For additional information regarding litigation related to state tax credits, see Note 3 under "Income Tax Matters."

The American Jobs Creation Act of 2004 created a tax deduction for the portion of income attributable to United States production activities as defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of the taxpayer's qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. This increase from 3% in 2006 to 6% was one of several factors that increased the Company's 2007 deduction by

$18.6 million in tax deductions. The resulting tax benefit was $6.5 million.

Unrecognized Tax Benefits On January 1, 2007, the Company adopted FIN 48 which requires companies to determine whether it is "more likely than not" that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties.

Prior to adoption of FIN 48, the Company had unrecognizedtax benefits which were previously accrued under Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies" of approximately $62 million. Upon adoption of FIN 48, an additional

$3 million of unrecognized tax benefits were recorded, which resulted in a total balance of $65 million. The $3 million relates to tax positions for which ultimate deductibility is highly certain, but for which there is uncertainty as to the timing of such deductibility. Of the total $65 million unrecognized tax benefits, $62 million would impact the Company's effective tax rate if recognized. For 2007, the total amount of unrecognized tax benefits increased by $24.2 million, resulting in a balance of $89.2 million as of December 31, 2007.

57

NOTES (continued)

Georgia Power Company 2007 Annual Report Changes during the year in unrecognized tax benefits were as follows:

2007 (in millions)

Unrecognized tax benefits as of adoption $ 65.0 Tax positions from current periods 20.5 Tax positions from prior periods 3.7 Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $ 89.2 Impact on the Company's effective tax rate, if recognized, is as follows:

2007 (in millions)

Tax positions impacting the effective tax rate $ 86.1 Tax positions not impacting the effective tax rate 3.1 Balance at end of year $ 89.2 Accrued interest for unrecognized tax benefits:

2007 (in millions)

Interest accrued as of adoption $ 2.7 Interest accrued during the year 4.4 Balance at end of year $ 7.1 The Company classifies interest on tax uncertainties as interest expense. Net interest accrued for the year ended December 31, 2007 was $7.1 million. The Company did not accrue any penalties on uncertain tax positions.

The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2002.

It is reasonably possible that the amount of the unrecognized benefit with respect to certain of the Company's unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the Georgia state tax credits litigation, production activities deduction methodology, and/or the conclusion or settlement of federal or state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See Note 3 under "Income Tax Matters" herein for additional information.

6. FINANCING Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its Class A preferred stock, preference stock, and common stock outstanding. The Company's Class A preferred stock ranks senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the Class A preferred stock and preference stock are subject to redemption at the option of the Company on or after a specified date (typically 5 or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock. In addition, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends.

58

NOTES (continued)

Georgia Power Company 2007 Annual Report Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

Long-Term Debt Payable to Affiliated Trusts The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as "Long-term Debt." The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts' payment obligations with respect to these securities. -During 2007, the Company redeemed junior subordinated notes and the related trust preferred securities issued by Georgia Power Capital Trusts V and VI. At December 31, 2007, preferred securities of $200 million were outstanding. See Note 1 under "Variable Interest Entities" for additional information on the accounting treatment for these trusts and the related securities.

Securities Due Within One Year A summary of the scheduled maturities and redemptions of securities due within one year at December 31 is as follows:

2007 2006 (in millions)

Capital lease $ 4 $ 4 Senior notes 195 300 Total $ 199 $ 304 Redemptions and/or maturities through 2012 applicable to total long-term debt are as follows: $199 million in 2008; $279 million in 2009; $4 million in 2010; $115 million in 2011; and $288 million in 2012.

Pollution Control Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is recquired to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company has incurred obligations in connection with the sale by public authorities of tax-exempt pollution control revenue bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2007 was $1.9 billion. Proceeds from certain issuances are restricted until the expenditures are incurred.

Senior Notes The Company issued $1.5 billion aggregate principal amount of unsecured senior notes in 2007. The proceeds of the issuance were used to repay a portion of the Company's short term indebtedness, fund note maturities, redeem long-term debt payable to affiliated trusts, and fund the Company's continuous construction program. At December 31, 2007 and 2006, the Company had $4.0 billion and

$2.8 billion of senior notes outstanding, respectively. These senior notes are effectively.subordinated to all secured debt of the Company, which aggregated $71 million at December 31, 2007.

Capital Leases Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2007 and 2006, the Company had a capitalized lease obligation for its corporate headquarters building of $69 million and $72 million, respectively, with an interest rate of 8.1%. For ratemaking purposes, the Georgia PSC.has treated the lease as an operating lease and has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the Georgia PSC. See Note I under "Regulatory Assets and Liabilities." At December 31, 2007 and 2006, the Company had capitalized lease obligations of $1.9 million for its vehicles and $4.1 million for its vehicles and the Plant Kraft coal unloading dock, respectively. However, for ratemaking purposes, these obligations are treated as operating leases and, as such, lease payments are charged to expense as incurred. The annual expense incurred for these leases in 2007, 2006, and 2005 was $9.2 million, 59

NOTES (continued)

Georgia Power Company 2007 Annual Report

$9.6 million, and $9.7 million, respectively. In March 2007, the Savannah Economic Development Authority Taxable 'Industrial Revenue Bonds First Series 1996 were redeemed; therefore, as of December 31, 2007, the Company no longer has a capital lease obligation for the Plant Kraft unloading dock.

Bank Credit Arrangements At the beginning of 2008, the Company had credit arrangements with banks totaling $1.2 billion, of which $8 million was .used to support outstanding letters of credit. Of these facilities, $40 million expires during 2008, with the remaining $1.1 billion expiring in 2012. The facility that expires in 2008 provides the option of converting borrowings into a two-year term loan. The Company expects to renew its facilities, as needed, prior to expiration. The agreements contain stated borrowing rates. All the agreements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees are less than 1/8 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.

The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65%, as defined in the arrangements.

For purposes of these definitions, indebtedness excludes the long-term debt payable to affiliated trusts and, in certain cases, other hybrid securities. In addition, the credit arrangements contain cross default provisions that would trigger an event of default if the Company defaulted on other indebtedness above a specified threshold. At December 31, 2007, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowings.

The $1.2 billion of unused credit arrangements provides liquidity support to the Company's variable rate pollution control~bonds and its commercial paper borrowing. The amount of variable rate pollution control bonds outstanding requiring liquidity support as of December 31, 2007 was $301 million. In addition, the Company borrows under a commercial paper program and an extendible commercial note program. The amount of commercial paper outstanding at December 31, 2007, 2006, and 2005 was $616 million,

$733 million, and $327 million,-respectively. There were no outstanding extendible commercial notes at December 31, 2007.

Commercial paper is included in notes payable on the balance sheets.

During 2007, the peak amount of short-term debt outstanding was $1.1 billion and the average amount outstanding was $638 million.

The average annual interest rate on short-term debt in 2007 was 5.3%.

Financial Instruments The Company enters into energy-related derivatives to hedge exposures to electricity, gas" and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. See Note 3 under. "Retail Regulatory Matters - Fuel Hedging Program" for information on the Company's fuel hedging program. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness related to energy related derivatives recorded in earnings in any period presented. At December 31, 2007, the $0.4 million fair value of net losses of derivative energy contracts were reflected in the financial statements as regulatory assets. The fair value gain or loss for hedges that are recoverable through the regulatory fuel clauses are recorded in regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2010. The Company enters into derivatives to hedge exposure to interest rate changes. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. As such, no material ineffectiveness has been recorded in earnings for any period presented.

60

NOTES (continued)

Georgia Power Company 2007 Annual Report At December 31, 2007, the Company had $539 million notional amounts of interest derivatives accounted for as cash flow hedges outstanding with net fair value gains/(losses) as follows:

Fair Value Notional Variable Rate Weighted Average Hedge Maturity Gain/(Loss)

Amount Received Fixed Rate Paid Date December 31, 2007 (in millions) (in millions)

$ 100 1-month LIBOR* 3.85% January 2008 $

$ 14 SIFMA Index ** 2.50% January 2008 $ -

$ 225 3-month LIBOR 5.26% March 2018 $ (10.4)

$ 100 3-month LIBOR 5.12% June 2018 $ (3.3)

$ 100 3-month LIBOR 5.28% February 2019 $ (3.6)

• Interest rate collar with variable rate based on a percentage of one-month LIBOR (showing rate cap)

• • Hedged using the Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA),

(Formerly the Bond Market Association/PSA Municipal Swap Index)

Subsequent to December 31, 2007, the Company entered into $601 million notional amounts of interest rate swaps related to variable rate debt through December 2009.

The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2007, 2006, and 2005, the Company settled gains/(losses) totaling $12.1 million,

$(3.9) million, and $0.9 million, respectively, upon termination of certain interest derivatives at the same time it issued debt. The effective portion of these gains/(losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative. Amounts reclassified from other comprehensive income to interest expense were immaterial for all periods presented. For 2008, pre-tax losses of approximately $3 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest related hedges in place through 2019 and has realized gains/(losses) that are being amortized through 2037.

7. COMMITMENTS Construction Program The Company currently estimates property additions to be approximately $2.0 billion, $2.0 billion, and $1.8 billion, in 2008, 2009, and 2010, respectively. These amounts include $116 million, $138 million, and $128 million in 2008, 2009, and 2010, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under "Fuel Commitments." The construction program is subject to periodic review and revision, and actual construction costs may vary from estimates because of numerous factors, including, but not limited to, changes in business conditions, changes in FERC rules and regulations, revised load growth estimates, changes in environmental regulations, changes in existing nuclear plants to meet new regulatory requirements, increasing costs of labor, equipment, and materials, and cost of capital.

At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program.

Long-Term Service Agreements The Company has entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the combustion turbines at the Plant McIntosh combined cycle facility. In summary, the LTSA stipulates that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

In general, this LTSA is in effect through two major inspection cycles per unit. Scheduled payments to GE, which are subject to price escalation, are made quarterly based on actual operating hours of the respective units. Total payments to GE under this agreement are currently estimated at $187.7 million over the remaining term of the agreement, which is currently projected to be approximately 10 years. However, the LTSA contains various cancellation provisions at the option of the Company.

The Company has also entered into an LTSA with GE through 2014 for neutron monitoring system parts and electronics at Plant 61

NOTES (continued)

Georgia Power Company 2007 Annual Report Hatch. Total remaining payments to GE under this agreement are currently estimated at $9.2 million. The contract contains cancellation provisions at the option of the Company. Payments made to GE prior to the performance of any work are recorded as a prepayment in the balance sheets. Work performed by GE is capitalized or charged to expense as appropriate net of any joint owner billings, based on the nature of the work.

The Company has entered into a LTSA with Mitsubishi Power Systems Americas, Inc. (MPS) for the purpose of providing certain parts and maintenance services for the three combined cycle units under construction at Plant McDonough, which are scheduled to go into service in February 2011, June 2011, and June 2012, respectively. The LTSA stipulates that MPS will perform all planned maintenance on each covered unit which includes the cost of all materials and services. MPS is also obligated to cover costs of unplanned maintenance on the gas turbines subject to limits specified in the LTSA.

This LTSA will commence in 2011 and is in effect through two major inspection cycles per covered unit. Periodic payments to MPS are to be made quarterly and will also be made based on the scheduled inspections for the respective covered units. Payments to MPS under this agreement, which are subject to price escalation, are currently estimated to be $536.8 million for the term of the agreement which is expected to be between 12 and 13 years. However, the LTSA contains various termination provisions at the option of the Company.

Limestone Commitments As part of the Company's program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment. Contracts are structured with tonnage minimums and maximums in order to account for changes in coal burn and sulfur content. The Company has a minimum contractual obligation of 3.8 million tons, equating to approximately $114.6 million through 2019. Estimated expenditures over the next five years are $4.5 million in 2008, $10.2 million in 2009, $19.2 million in 2010, $14.6 million in 2011, and $14.9 million in 2012.

Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery.

Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2007.

Total estimated minimum long-term obligations at December 31, 2007 were as follows:,

Commitments Natural Gas Coal Nuclear Fuel (in millions) 2008 $ 684 $1,653 $ 116 2009 503 1,070 138 2010 229 449 128 2011 375 82 110 2012 386. 47 110 2013 and thereafter 2,803 21 125 Total $ 4,980 $3,322 $ 727 Additional commitments for fuel will be required to supply the Company's future needs. Total charges for nuclear fuel included in fuel expense were $79 million, $71 million and $70 million for the years 2007, 2006, and 2005, respectively.

SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure they will not subsidize or be responsible 62

NOTES (continued)

Georgia Power Company 2007 Annual Report for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.

Purchased Power Commitments The Company has commitments regarding a portion of a 5% interest in Plant Vogtle owned by MEAG that are in effect until the latter of the retirement of the plant or the latest stated maturity date.of MEAG's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. Portions of the capacity payments relate to costs in excess of Plant Vogtle's allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity and energy is included in purchased power from non-affiliates in the statements of income. Capacity payments totaled $46 million,

$49 million, and $54 million in 2007, 2006, and 2005, respectively. The Company also has entered into other various long-term power purchase agreements (PPAs). Estimated total long-term obligations under these commitments at December 31, 2007 were as follows:

Vogtle Affiliated Non-Affiliated Caoacitv Payments PPA PPA (in millions) 2008 $ 49 $ 209 $ 84 2009 53 209 90 2010 53 153 132 2011 51 119 148 2012 49 107 107 2013 and thereafter 139 702 1,504 Total $ 394 $ 1,499 $ 2,065 Operating Leases The Company has entered into various operating leases with various terms and expiration dates.. Rental expenses related to these operating leases totaled $31 million for 2007, $33 million for 2006, and $39 million for 2005.

At December 31, 2007, estimated minimum lease payments for these noncancelable operating leases were as follows:

Minimum Lease Payments Rail Cars Other Total (in millions) 2008 $ 18 $ 11 $ 29 2009 17 9 26 2010 16 7 23 201.1 16 6 22 2012 9 3 12 2013 and thereafter 24 5 29 Total $100 $41 $141 In addition to the rental commitments above, the Company has obligations upon expiration of certain rail car leases with respect to the residual value of the leased property. These leases expire in 2011 and the Company's maximum obligation is $40.7 million. At the termination of the leases, at the Company's option, the Company may either exercise its purchase option or the property can be sold to a third party. The.Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligation. A portion of the rail car lease obligations is shared with the joint owners of Plants Scherer and Wansley. A majority of the rental expenses related to the rail car leases are fully. recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and. the remaining portion is recovered through base rates.

63

NOTES (continued)

Georgia Power Company 2007 Annual Report Guarantees Alabama Power has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Alabama Power has also guaranteed $50 million in senior notes issued by SEGCO. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company's then proportionate ownership of stock of SEGCO if Alabama Power is called upon to make such payment under its guaranty.

As discussed earlier in this Note under "Operating Leases," the Company has entered into certain residual value guarantees related to rail car leases.

8. STOCK OPTION PLAN Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2007, 1,658 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however for employees who are eligible for retirement the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards a change in control will provide accelerated vesting.

The Company's activity in the stock option plan for 2007 is summarized below:

Shares Subject to Weighted Average Option Exercise Price Outstanding at December 31, 2006 7,830,583 $ 28.42 Granted 1,432,410 36.42 Exercised (1,717,486) 25.59 Cancelled (7,398) 30.13 Outstanding at December 31, 2007 7,538,109 S$30.59 Exercisable at December 31, 2007 4,837,923 $ 28.13 The number of stock options vested, and expected to vest in the future, as of December 31, 2007 was not significantly different from the number of stock options outstanding at December 31, 2007 as stated above. At December 31, 2007, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.4 years and 5.2 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $61.5 million and $51.4 million, respectively.

As of December 31, 2007, there was $2.3 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.

The total intrinsic value of options exercised during the years ended December 31, 2007, 2006, and 2005 was $17.4 million,

$10.3 million, and $24.2 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $6.7 million, $4.0 million, and $9.4 million, respectively, for the years ended December 31, 2007, 2006, and 2005.

9. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC. that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's Plants Hatch and Vogtle.

The Act provides funds up to $10.8 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage 64

NOTES (continued)

Georgia Power Company 2007 Annual Report provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests, is $203 million, per incident, but not more than an aggregate of $30 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before August 31, 2008.

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

Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 billion for losses in excess of the $500 million primary coverage. This excess insurance-is also provided by NEIL.

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week waiting period.

Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to.

the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $51 million.

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12 month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

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

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

65

NOTES (continued)

Georgia Power Company 2007 Annual Report

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2007 and 2006 is as follows:

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

March 2007 $ 1,657 $ 279 $ 131 June 2007 1,844 361 188 September 2007 2,444 688 400 December 2007 1,627 189 117 March 2006 $ 1,584 $ 288 $ 132 June 2006 1,808 386 197 September 2006 2,275 662 382 December 2006 1,579 174 76 The Company's business is influenced by seasonal weather conditions.

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SELECTED FINANCIAL AND OPERATING DATA 2003-2007 Georgia Power Company 2007 Annual Report 2007 2006 2005 2004 2003 Operating Revenues (in thousands) $7,571,652 $7,245,644 $7,075,837 $5,727,768 $5,228,625 Net Income after Dividends on Preferred and Preference Stock (in thousands) $836,136 $787,225 $744,373 $682,793 $654,036 Cash Dividends on Common Stock (in thousands) $689,900 $630,000 $582,800 $588,700 $588,800 Return on Average Common Equity (percent) 13.50 13.80 14.08 13.87 14.01 Total Assets (in thousands) $20,822,761 $19,308,730 $17,898,445 $16,598,778 $15,527,223 Gross Property Additions (in thousands) $1,862,449 $1,276,889 $958,563 $1,252,197 $783,053 Capitalization (in thousands):

Common stock equity $6,435,420 $5,956,251 $5,452,083 $5,123,276 $4,723,299 Preferred and preference stock 265,957 44,991 43,909 58,547 14,569 Mandatorily redeemable preferred securities - - - - 940,000 Long-term debt 5,937,792 5,211,912 5,365,323 4,916,694 3,984,825 Total (excluding amounts due within one year) $12,639,169 $11,213,154 $10,861,315 $10,098,517 $9,662,693 Capitalization Ratios (percent):

Common stock equity 50.9 53.1 50.2 50.7 48.9 Preferred and preference stock 2.1 0.4 0.4 0.6 0.2 Mandatorily redeemable preferred securities - - - - 9.7 Long-term debt 47.0 46.5 49.4 48.7 41.2 Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 Security Ratings:

Preferred and Preference Stock -

Moody's Baal Baal Baal Baal Baal Standard and Poor's BBB+ BBB+ BBB+ BBB+ BBB+

Fitch A A A A A Unsecured Long-Term Debt -

Moody's A2 A2 A2 A2 A2 Standard and Poor's A A A A A Fitch A+ A+ A+ A+ A+-

Customers (year-end):

Residential 2,024,520 1,998,643 1,960,556 1,926,215 1,890,790 Commercial 295,478 294,654 289,009 283,507 275,378 Industrial 8,240 8,008 8,290 7,765 7,989 Other 4,807 4,371 4,143 4,015 3,940 Total 2,333,045 2,305,676 2,261,998 2,221,502 2,178,097 Employees (year-end) 9,270 9,278 9,273 9,294 9,263 N/A = Not Applicable.

67

SELECTED FINANCIAL AND OPERATING DATA 2003-2007 (continued)

Georgia Power Company 2007 Annual Report 2007 2006 2005 2004 2003 Operating Revenues (in thousands):

Residential $ 2,442,501 $2,326,190 $2,227,137 $1,900,961 $1,726,543 Commercial 2,576,058 2,423,568 2,357,077 1,933,004 1,767,487 Industrial 1,403,852 1,382,213 1,406,295 1,217,536 1,051,034 Other 75,592 73,649 73,854 67,250 63,715 Total retail 6,498,003 6,205,620 6,064,363 5,118,751 4,608,779 Wholesale - non-affiliates 537,913 551,731 524,800 251,581 265,029 Wholesale - affiliates 277,832 252,556 275,525 172,375 181,355 Total revenues from sales of electricity 7,313,748 7,009,907 6,864,688 5,542,707 5,055,163 Other revenues 257,904 235,737. 211,149 .185,061 173,462 Total $7,571,652 $7,245,644 $7,075,837 $5,727,768 $5,228,625 Kilowatt-Hour Sales (in thousands):

Residential 26,840,275 26,206,170 25,508,472 24,829,833 23,532,467 Commercial 33,056,632 32,112,430 31,334,182 29,553,893 28,401,764 Industrial 25,490,035 25,577,006 25,832,265 27,197,843 26,564,261 Other 697,363 660,285 737,343 744,935 732,900 Total retail 86,084,305 84,555,891 83,412,262 82,326,504 79,231,392 Sales for resale - non-affiliates 10,577,969 10,685,456 10,588,891 5,429,911 8,353,046 Sales for resale - affiliates 5,191,903 5,463,463 5,033,165 4,925,744 6,029,398 Total 101,854,177 100,704,810 99,034,318 92,682,159 93,613,836 Average Revenue Per Kilowatt-Hour (cents):

Residential 9.10 8.88 8.73 7.66 7.34 Commercial 7.79 7.55 7.52 6.54 6.22 Industrial 5.51 5.40 5.44 4.48 3.96 Total retail 7.55 7.34 . 7.27 6.22 5.82 Wholesale 5.17 4.98 5.12 4.09 3.10 Total sales 7.18 6.96 6.93 5.98 5.40 Residential Average Annual Kilowatt-Hour Use Per Customer 13,315 13,216 13,119 13,002 12,555 Residential Average Annual Revenue Per Customer $1,212 $1,173 . $1,145 $995 $921 Plant Nameplate Capacity Ratings (year-end) (megawatts) 15,995 15,995 15,995 14,743 14,768 Maximum Peak-Hour Demand (megawatts):

Winter 13,817 13,528 14,360 13,087' 13,929 Summer 17,974 17,159 16,925 16,129 15,575 Annual Load Factor (percent) 57.5 61.8 59.4 61.0 61.6 Plant Availability (percent):

Fossil-steam 90.8 91.4 90.0 87.1 85.9 Nuclear 92.4 90:7 89.3 94.8 94.1 Source of Energy Supply (percent):

Coal 61.5 59..0 60.7 57.6 58.7 Nuclear 14.6 14.4 14.5 16.5 16.2 Hydro 0.5 0.9 1.19 1.5 2.0 Oil and gas 5.5 5.0 3.0 0.2 0.4 Purchased power -

From non-affiliates 3.8 3.8 4.6 6.0 6.1 From affiliates 14.1 16.9 15.3 18.2 16.6 Total 100.0 100.0 100.0 100.0 100.0 68

DIRECTORS AND OFFICERS.

Georgia Power Company 2007 Annual Report Directors Officers Gus H. Bell III Michael D; Garrett Chairman and President President and Chief Executive Officer Hussey, Gay, Bell and DeYoung Georgia Power Company (Retired effective 8/6/07)

Mickey A. Brown Robert L. Brown, Jr. Executive Vice President President and Chief Executive Officer 'Customer Service Organization R. L. Brown & Associates, Inc.

Cliff S. Thrasher Ronald D. Brown Executive Vice President, Chief Financial Officer President and Chief Executive Officer and Treasurer Atlanta Life Financial Group Chris C. Womack Anna R. Cablik Executive Vice President Owner and President External Affairs Anatek, Inc. & Anasteel & Supply Co., LLC Judy M. Anderson Michael D. Garrett Senior Vice President President and Chief Executive Officer Charitable Giving Georgia Power Company Richard L. Holmes David M. Ratcliffe Senior Vice President Chairman, President and Chief Executive Officer Metro Region The Southern Company E. Lamont Houston Jimmy C. Tallent Senior Vice President President and Chief Executive Officer Customer Service and Sales United Community Banks, Inc.

(Elected effective 5/16/07) Douglas E. Jones Senior Vice President D. Gary Thompson Fossil & Hydro Generation and Retired from Wachovia Corporation Senior Production Officer Richard W. Ussery James H. Miller III Retired from Total System Services, Inc. Senior Vice President and General Counsel W. Jerry Vereen Chairman, President and Chief Executive Officer Michael K. Anderson Riverside Manufacturing Company & Subsidiaries Vice President Corporate Services E. Jenner Wood III Chairman, President and Chief Executive Officer W. Craig Barrs SunTrust Bank, Central Group Region Vice President Coastal Robert A. Bell Vice President Human Resources (Retired effective 4/1/08) 69

DIRECTORS AND OFFICERS Georgia Power Company 2007 Annual Report Rebecca A. Blalock Jacki W. Lowe Vice President Region Vice President Information Resources West P. Mike Clanton Daniel M. Lowery Vice President Corporate Secretary Customer Service Terri H. Lupo Ann P. Daiss Region Vice President Vice President, Comptroller and South Chief Accounting Officer Frank J. McCloskey Walter Dukes Vice President Region Vice President Diversity East Leslie R. Sibert A. Bryan Fletcher Vice President Vice President Transmission Supply Chain Management James E. Sykes, Jr.

J. Kevin Fletcher Region Vice President Vice President Northeast Community and Economic Development Gene L. Ussery Jeff G. Franklin Vice President Region Vice President Distribution Northwest (Retired effective 4/1/07)

Oscar C. Harper IV Thomas J. Wicker Vice President Region Vice President Governmental & Regulatory Affairs and Central Resource Planning & Nuclear Development Anthony L. Wilson

0. Ben Harris Vice President Vice President Distribution Land (Elected effective 2/10/07)

Charles H. Huling W. Tal Wright Vice President Vice President Environmental Affairs Corporate Communication Marsha S. Johnson E. Wayne Boston Vice President Assistant Secretary and Human Resources Assistant Treasurer (Elected effective 4/1/08)

Robert B. Morris Anne H. Kaiser Assistant Comptroller and Assistant Secretary Vice President Sales Mark K. Tate Assistant Comptroller 70

CORPORATE INFORMATION Georgia Power Company 2007 Annual Report General All of the outstanding shares of the Company's This annual report is submitted for general preferred and preference stock are registered information and is not intended for use in in the name of Cede & Co., as nominee for The connection with any sale or purchase of, or any Depository Trust Company.

solicitation of offers to buy or sell, securities.

Form 10-K Profile A copy of the Form 10-K as filed with the The Company produces and delivers electricity as Securities and Exchange Commission will be an integrated utility to retail customers within the provided upon written request to the office of State of Georgia and to wholesale customers in the Corporate Secretary. For additional the Southeast. The Company sells electricity to information, contact the office of the Corporate approximately 2.3 million customers within its Secretary at (404) 506-7450.

service area. In 2007, retail energy sales accounted for 85 percent of the Company's total Georgia Power Company sales of 101.9 billion kilowatt-hours. 241 Ralph McGill Boulevard, N.E.

Atlanta, GA 30308-3374 The Company is a wholly owned subsidiary of The (404) 506-6526 Southern Company, which is the parent company of four traditional operating companies, a wholesale Auditors generation subsidiary, and other direct and indirect Deloitte & Touche LLP subsidiaries. There is no established public trading Suite 1500 market for the Company's common stock. 191 Peachtree Street, N.E.

Atlanta, GA 30303 Trustee, Registrar, and Interest Paying Agent All series of Senior Notes and Trust Preferred Legal Counsel Securities Troutman Sanders LLP The Bank of New York 600 Peachtree Street, N.E.

101 Barclay Street, Floor 8W Suite 5200 New York, New York 10286 Atlanta, GA 30308 Registrar, Transfer Agent, and Dividend Paying Agent 6 1/8% Series Class A Preferred Stock Southern Company Services, Inc.

Stockholder Services P.O. Box 54250 Atlanta, GA 30308-0250 (800) 554-7626 6.50% Series 2007A Preference Stock Southern Company Services, Inc.

Stockholder Services P.O. Box 54250 Atlanta, GA 30308-0250 (800) 554-7626 71

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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, 2008 2007 2008 2007 OPERATING REVENUES:

Retail sales $1,830,753 $1,585,563 $3,405,760 $2,997,892 Sales for resale--

Non-affiliates 142,276 135,055 294,968 278,822 Affiliates 72,164 58,826 146,074 100,614 Other revenues 65,969 64,705 129,207 123,991 Total operating revenues 2,111,162 1,844,149 3,976,009 3,501,319 OPERATING EXPENSES:

Operation--

Fuel 683,299 650,830 1,321,222 1,244,724 Purchased power--

Non-affiliates 107,723 67,670 165,754 113,763 Affiliates 247,842 179,655 500,777 364,197 Other 266,024 249,538 507,116 480,286 Maintenance 125,757 136,816 253,480 261,258 Depreciation and amortization 159,204 127,262 309,812 253,411 Taxes other than income taxes 79,485 71,610 150,771 143,951 Total operating expenses 1,669,334 1,483,381 3,208,932 2,861,590 OPERATING INCOME 441,828 360,768 767,077 639,729 OTHER INCOME (EXPENSE):

Allowance for equity funds used during construction 23,981 14,687 51,738 27,866 Interest income 1,050 632 1,837 1,107 Interest expense, net of amounts capitalized (80,700) (73,074) (164,008) (143,661)

Interest expense to affiliate trusts (3,028) (14,006) (6,057) (28,884)

Other income (expense), net 1,372 301 (1,922) .(3,915)

Total other income and (expense) (57,325) (71,460) (118,412) (147,487)

EARNINGS BEFORE INCOME TAXES 384,503 289,308 648,665 492,242 Income taxes 132,279 100,204 216,080 171,184 NET INCOME 252,224 189,104 432,585 321,058 DIVIDENDS ON PREFERRED STOCK 4,346 689 8,691 1,378 NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $247,878 $188,415 $423,894 $319,680 Note: Certain priorperiod amounts have been reclassifiedto conform with currentperiodpresentation.

GEORGIA POWER COMPANY CONDENSED BALANCE SHEETS (UNAUDITED)

I (~Stated in Thousands of Dollars).

At June 30, At June 30, 2008 2007 ASSETS CURRENT ASSETS:

Cash and cash equivalents $15,035 $27,205 Restricted Cash 41,198 Receivables--

Customer accounts receivable 608,671 515,390 Unbilled revenues 215,656 179,542 Under recovered regulatory clause revenue 404,855 434,873 Other accounts and notes receivable 75,819 99,171 Affiliated companies 53,397 33,525 Accumulated provision for uncollectible accounts (8,269) (8,576)

Fossil fuel stock, at average cost 433,436 443,443 Materials and supplies, at average cost 349,013 315,962 Other 311,164 240,585 Total Current Assets 2,499,975 2,281,120 PROPERTY, PLANT AND EQUIPMENT:

In service 23,280,746 21,498,606 Less accumulated provision for depreciation 8,924,909 8,525,350 14,355,837 12,973,256 Nuclear fuel, at amortized cost 256,546 171,178 Construction work in progress 1,415,177 1,401,586 Total Property, Plant and Equipment 16,027,560 14,546,020 OTHER PROPERTY AND INVESTMENTS:

Equity investments in unconsolidated subsidiaries 58,188 60,986 Nuclear decommissioning trusts 549,815 578,358 Other 42,847 36,631 Total Other Property and Investments 650,850 675,975 DEFERRED CHARGES AND OTHER ASSETS:

Deferred charges related to income taxes 555,156 517,268 Prepaid pension costs 1,055,718 702,399 Unamortized debt issuance expense 104,581 81,170 Unamortized loss on reacquired debt 168,488 177,164 Deferred under recovered regulatory clause revenues 311,479 395,250 Other 631,614 579,777 Total Deferred Charges and Other Assets 2,827,036 2,453,028 TOTAL ASSETS $22,005,421 $19,956,143 Note: Certainpriorperiod amounts have been reclassifiedto conform with currentperiod presentation.

GEORGIA POWER COMPANY CONDENSEDBALANCE SHEETS (UNAUDITED)

(Stated in Thousands of Dollars)

At June 30, At June 30, 2008 2007 LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES:

Securities due within one year $303,353 $303,059 Notes payable 367,979 812,777 Accounts payable --

Affiliated companies 331,132 246,546 Other 486,433 414,073 Customer deposits 181,155 166,457 Taxes accrued Income taxes 104,110 173,690 Other 157,797 170,362 Interest accrued 79,734 77,977 Vacation pay accrued 55,064 49,485 Other 318,949 350,589 Total Current Liabilities 2,385,706 2,765,015 LONG-TERM DEBT 6,432,552 5,087,890 LONG-TERM DEBT PAYABLE TO AFFILIATED TRUSTS 206,186 515,465 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred income taxes 2,895,715 2,860,724 Deferred credits related to income taxes 144,338 152,052 Accumulated deferred investment tax credits 262,672 275,597 Employee benefits provisions 704,191 714,979 Asset retirement obligations 667,049 644,199 Other 1,284,257 841,939 Total Deferred Credits and Other Liabilities 5,958,222 5,489,490 PREFERRED STOCK 265,957 44,991 COMMON STOCKHOLDER'S EQUITY:

Common stock 398,473 398,473 Paid-in capital 3,631,784 3,319,143 Retained earnings

• 2,739,357 2,332,081 Accumulated other comprehensive income (12,816) 3,595 Total Common Stockholder's Equity 6,756,798 6,053,292 TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $22,005,421 $19,956,143 Note: Certainpriorperiod amounts have been reclassifiedto conform with current periodpresentation.

GEORGIA POWER COMPANY CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Stated in Thousands of Dollars)

FOR THE SIX MONTHS ENDED JUNE 2008 2007 OPERATING ACTIVITIES:

Net income $432,585 $321,058 Adjustments to reconcile net income to net cash provided by operating activities --

Depreciation and amortization 367,910 302,523 Deferred income taxes and investment tax credits, net 29,175 12,347 Deferred expenses - affiliated 21,571 21,933 Allowance for funds used during construction (51,738) (27,866)

Pension, postretirement, and other employee benefits 6,304 6,035 Stock option expense 3,261 4,680 Other, net 16,814 8,013 Changes in certain current assets and liabilities --

Receivables, net (193,372) (46,080)

Fossil fuel stock (40,214) (51,433)

Materials and supplies (15,781) (12,399)

Other current assets (14,873) (43,760)

Accounts payable 102,384 814 Taxes accrued (12,300) (60,944)

Other current liabilities 25,905 (53,771)

NET CASH PROVIDED FROM OPERATING ACTIVITIES 677,631 381,150 INVESTING ACTIVITIES:

Gross property additions (992,317) (753,046)

Distribution of restricted cash from pollution control bonds 13,221 Nuclear decommissioning trust fund purchases (225,477) (184,246)

Nuclear decommissioning trust fund sales 218,597 177,366 Cost of removal net of salvage (15,957) (18,042)

Other (9,554) 14,458 NET CASH USED FOR INVESTING ACTIVITIES (1,011,487) (763,510)

FINANCING ACTIVITIES:

Increase (decrease) in notes payable, net (347,612) 79,495 Proceeds --

Senior notes 500,000 850,000 Pollution control bonds 53,000 Capital contributions from parent company 251,262 269,949 Other long-term debt 300,000 Gross excess tax benefit of stock options 1,887 3,410 Redemptions -

Pollution Control Bonds Senior notes (45,812)

Preferred stock Special deposits - redemption funds Payment of preferred stock dividends (8,309) (1,550)

Payment of common stock dividends (360,600) (344,950)

Other (10,317) (463,639)

NET CASH PROVIDED FROM FINANCING ACTIVITIES 333,499 392,715 NET CHANGE IN CASH AND CASH EQUIVALENTS (357) 10,355 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 15,392 16,850 CASH AND CASH EQUIVALENTS AT END OF PERIOD $15,035 $27,205 Note: Certain priorperiodamounts have been reclassifiedto conform with currentperiod presentation.

GEORGIA POWER COMPANY PROJECTED STATEMENT OF CASH FLOWS 2009 FORECAST (Stated in Thousands of Dollars) 2009 FORECAST.

OPERATING ACTIVITIES Net income before preferred dividends $1,011,025 Principal noncash items-Depreciation and amortization 794,071 Deferred income taxes, net (58,250)

Allowance for equity funds used during construction (119,539)

Pension, postretirement and other employee benefits (28,092)

Other, net 523,325 Change in current assets & liabilities-Receivables 22,290 Inventories 8,887 Accounts payable 13,335 Other current assets and liabilities 66,910 NET CASH PROVIDED FROM OPERATING ACTIVITIES 2,233,962 INVESTING ACTIVITIES, Gross property additions (2,578,801)

Cost of removal, net of salvage (33,221)

Allowance for equity funds used during construction 119,539 Other property and investments (14,502)

NET CASH USED FOR INVESTING ACTIVITIES (2,506,985)

FINANCING ACTIVITIES Increase in notes payable, net 22,451 Proceeds -

Senior notes 600,000 Preferred stock 300,000 Capital contributions from parent company 424,924 Redemptions -

Senior notes (275,000)

Trust preferred securities Capitalized leases (3,920)

Stock Option Expense 14,226 Payment of preferred stock dividends (24,784)

Payment of common stock dividends (765,800)

Other (19,074)

NET CASH USED FOR FINANCING ACTIVITIES 273,023 NET INC (DEC) IN CASH AND TEMPORARY CASH INVESTMENTS $0 CASH AND TEMPORARY CASH INVESTMENTS AT BEG OF PERIOD $223,991 CASH AND TEMPORARY CASH INVESTMENTS AT END OF PERIOD $223,991