10-K 1 form10k.txt FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2001 =============================================================================== UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2001 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from to Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification No. 1-3526 The Southern Company 58-0690070 (A Delaware Corporation) 270 Peachtree Street, N.W. Atlanta, Georgia 30303 (404) 506-5000 1-3164 Alabama Power Company 63-0004250 (An Alabama Corporation) 600 North 18th Street Birmingham, Alabama 35291 (205) 257-1000 1-6468 Georgia Power Company 58-0257110 (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526 0-2429 Gulf Power Company 59-0276810 (A Maine Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111 0-6849 Mississippi Power Company 64-0205820 (A Mississippi Corporation) 2992 West Beach Gulfport, Mississippi 39501 (228) 864-1211 1-5072 Savannah Electric and Power Company 58-0418070 (A Georgia Corporation) 600 East Bay Street Savannah, Georgia 31401 (912) 644-7171 =============================================================================== Securities registered pursuant to Section 12(b) of the Act:1 Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is registered on the New York Stock Exchange. Title of each class Registrant ------------------- ----------- Common Stock, $5 par value The Southern Company Company obligated mandatorily redeemable preferred securities, $25 liquidation amount 7.75% Cumulative Quarterly Income Preferred Securities 2 7 1/8% Trust Originated Preferred Securities3 6.875% Cumulative Quarterly Income Preferred Securities4 --------------------------------------------------- Class A preferred, cumulative, $25 stated capital Alabama Power Company 5.20% Series 5.83% Series Senior Notes 7 1/8% Series A 7% Series C 7% Series B 6.75% Series J Company obligated mandatorily redeemable preferred securities, $25 liquidation amount 7.375% Trust Preferred Securities5 7.60% Trust Originated Preferred Securities6 --------------------------------------------------- Senior Notes Georgia Power Company 6 7/8% Series A 6 5/8% Series D 6.60% Series B Company obligated mandatorily redeemable preferred securities, $25 liquidation amount 7.75% Trust Preferred Securities7 7.60% Trust Preferred Securities8 7.75% Cumulative Quarterly Income Preferred Securities9 6.85% Trust Preferred Securities10 ------------------------------------------------------ =============================================================================== ---------------------------- 1 As of December 31, 2001. 2 Issued by Southern Company Capital Trust III and guaranteed by The Southern Company. 3 Issued by Southern Company Capital Trust IV and guaranteed by The Southern Company. 4 Issued by Southern Company Capital Trust V and guaranteed by The Southern Company. 5 Issued by Alabama Power Capital Trust I and guaranteed by Alabama Power Company. 6 Issued by Alabama Power Capital Trust II and guaranteed by Alabama Power Company. 7 Issued by Georgia Power Capital Trust I and guaranteed by Georgia Power Company. 8 Issued by Georgia Power Capital Trust II and guaranteed by Georgia Power Company. 9 Issued by Georgia Power Capital Trust III and guaranteed by Georgia Power Company. 10 Issued by Georgia Power Capital Trust IV and guaranteed by Georgia Power Company. Company obligated mandatorily redeemable Gulf Power Company preferred securities, $25 liquidation amount 7.625% Cumulative Quarterly Income Preferred Securities11 7.00% Cumulative Quarterly Income Preferred Securities12 7.375% Trust Preferred Securities13 ------------------------------------------------------ Depositary preferred shares, Mississippi Power Company each representing one-fourth of a share of preferred stock, cumulative, $100 par value 6.32%Series 6.65% Series Company obligated mandatorily redeemable preferred securities, $25 liquidation amount 7.75% Trust Originated Preferred Securities14 --------------------------------------------------- Company obligated mandatorily Savannah Electric and Power Company redeemable preferred securities, $25 liquidation amount 6.85% Trust Preferred Securities15 Securities registered pursuant to Section 12(g) of the Act:16 Title of each class Registrant ------------------- ---------- Preferred stock, cumulative, $100 par value Alabama Power Company 4.20% Series 4.60% Series 4.72% Series 4.52% Series 4.64% Series 4.92% Series Class A preferred, cumulative, $100,000 stated capital Auction (1993 Series) Class A preferred, cumulative, $100 stated capital Auction (1988 Series) ---------------------------------------------------------- Preferred stock, cumulative, Georgia Power Company $100 stated value $4.60 Series (1954) ---------------------------------------------------------- ============================================================================== --------------------- 11 Issued by Gulf Power Capital Trust I and guaranteed by Gulf Power Company. 12 Issued by Gulf Power Capital Trust II and guaranteed by Gulf Power Company. 13 Issued by Gulf Power Capital Trust III and guaranteed by Gulf Power Company. 14 Issued by Mississippi Power Capital Trust I and guaranteed by Mississippi Power Company. 15 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah Electric and Power Company. 16 As of December 31, 2001. Preferred stock, cumulative, $100 par value Gulf Power Company 4.64% Series 5.44% Series 5.16% Series ---------------------------------------------------------- Preferred stock, cumulative, $100 par value Mississippi Power Company 4.40% Series 4.60% Series 4.72% Series 7.00% Series ---------------------------------------------------------- Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No___ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( ) Aggregate market value of voting stock held by non-affiliates of The Southern Company at February 28, 2002: $17.8 billion. Each of such other registrants is a wholly-owned subsidiary of The Southern Company. A description of registrants' common stock follows:
Description of Shares Outstanding Registrant Common Stock at February 28, 2002 ---------- ------------ -------------------- The Southern Company Par Value $5 Per Share 700,085,336 Alabama Power Company Par Value $40 Per Share 6,000,000 Georgia Power Company No Par Value 7,761,500 Gulf Power Company No Par Value 992,717 Mississippi Power Company Without Par Value 1,121,000 Savannah Electric and Power Company Par Value $5 Per Share 10,844,635
Documents incorporated by reference: specified portions of The Southern Company's Proxy Statement relating to the 2002 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Information Statements of Alabama Power Company, Georgia Power Company, Gulf Power Company and Mississippi Power Company relating to each of their respective 2002 Annual Meeting of Shareholders are incorporated by reference into PART III. This combined Form 10-K is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Savannah Electric and Power Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies. ===============================================================================
Table of Contents Page PART I Item 1 Business Mirant Corporation........................................................ I-1 The SOUTHERN System....................................................... I-2 Operating Companies....................................................... I-2 Southern Power............................................................ I-2 Other Business............................................................ I-3 Certain Factors Affecting the Industry.................................... I-3 Construction Programs..................................................... I-4 Financing Programs........................................................ I-6 Fuel Supply............................................................... I-7 Territory Served by the Operating Companies............................... I-8 Competition............................................................... I-11 Regulation................................................................ I-13 Rate Matters.............................................................. I-16 Employee Relations........................................................ I-18 Item 2 Properties.................................................................. I-20 Item 3 Legal Proceedings........................................................... I-24 Item 4 Submission of Matters to a Vote of Security Holders......................... I-27 Executive Officers of SOUTHERN.............................................. I-28 Executive Officers of ALABAMA............................................... I-29 Executive Officers of GEORGIA............................................... I-30 Executive Officers of GULF.................................................. I-31 Executive Officers of MISSISSIPPI........................................... I-32 PART II Item 5 Market for Registrants' Common Equity and Related Stockholder Matters....... II-1 Item 6 Selected Financial Data..................................................... II-2 Item 7 Management's Discussion and Analysis of Results of Operations and Financial Condition................................................... II-2 Item 7A Quantitative and Qualitative Disclosures about Market Risk.................. II-2 Item 8 Financial Statements and Supplementary Data................................. II-3 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................................... II-4 PART III Item 10 Directors and Executive Officers of the Registrants........................ III-1 Item 11 Executive Compensation..................................................... III-3 Item 12 Security Ownership of Certain Beneficial Owners and Management............................................................... III-9 Item 13 Certain Relationships and Related Transactions............................. III-10 PART IV Item 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K.............................................................. IV-1
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DEFINITIONS When used in Items 1 through 5 and Items 10 through 14, the following terms will have the meanings indicated. Term Meaning AEC........................................... Alabama Electric Cooperative, Inc. AFUDC......................................... Allowance for Funds Used During Construction ALABAMA....................................... Alabama Power Company AMEA.......................................... Alabama Municipal Electric Authority Clean Air Act................................. Clean Air Act Amendments of 1990 Dalton........................................ City of Dalton, Georgia DOE........................................... United States Department of Energy EMF........................................... Electromagnetic field Energy Act.................................... Energy Policy Act of 1992 Energy Solutions.............................. Southern Company Energy Solutions, Inc. Entergy Gulf States........................... Entergy Gulf States Utilities Company EPA........................................... United States Environmental Protection Agency FERC.......................................... Federal Energy Regulatory Commission FPC........................................... Florida Power Corporation FP&L.......................................... Florida Power & Light Company GEORGIA....................................... Georgia Power Company GULF.......................................... Gulf Power Company Holding Company Act........................... Public Utility Holding Company Act of 1935, as amended IBEW.......................................... International Brotherhood of Electrical Workers IPP........................................... Independent power producer IRP........................................... Integrated Resource Plan IRS........................................... Internal Revenue Service JEA........................................... Jacksonville Electric Authority MEAG.......................................... Municipal Electric Authority of Georgia MESH.......................................... Mobile Energy Services Holdings Mirant........................................ Mirant Corporation (formerly Southern Energy, Inc.) MISSISSIPPI................................... Mississippi Power Company NRC........................................... Nuclear Regulatory Commission OPC........................................... Oglethorpe Power Corporation operating companies........................... ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH PPA........................................... Purchased Power Agreements PSC........................................... Public Service Commission RFP........................................... Request for Proposal RTO........................................... Regional Transmission Organization RUS........................................... Rural Utility Service (formerly Rural Electrification Administration)
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DEFINITIONS (continued) SAVANNAH...................................... Savannah Electric and Power Company SCS........................................... Southern Company Services, Inc. (the system service company) SEC........................................... Securities and Exchange Commission SEGCO......................................... Southern Electric Generating Company SEPA.......................................... Southeastern Power Administration SERC.......................................... Southeastern Electric Reliability Council SMEPA......................................... South Mississippi Electric Power Association SOUTHERN...................................... The Southern Company Southern LINC................................. Southern Communications Services, Inc. Southern Management Development............... Southern Management Development, Inc. Southern Nuclear.............................. Southern Nuclear Operating Company, Inc. Southern Power................................ Southern Power Company SOUTHERN system............................... SOUTHERN, the operating companies, Southern Power, SEGCO, Southern Nuclear, SCS, Southern LINC, Energy Solutions and other subsidiaries Southern Telecom.............................. Southern Telecom, Inc. TVA........................................... Tennessee Valley Authority
iii CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This Annual Report on Form 10-K contains forward-looking and historical information. Forward-looking information includes, among other things, statements concerning the strategic goals for SOUTHERN's new wholesale business and also SOUTHERN's goals for dividend payout ratio, earnings per share and earnings growth. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential" or "continue" or the negative of these terms or other comparable terminology. SOUTHERN cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental and other laws and regulations to which SOUTHERN and its subsidiaries are subject, as well as changes in application of existing laws and regulations; current and future litigation, including the pending EPA civil action against certain SOUTHERN subsidiaries and the race discrimination litigation against certain SOUTHERN subsidiaries; the effects, extent and timing of the entry of additional competition in the markets in which SOUTHERN's subsidiaries operate; the impact of fluctuations in commodity prices, interest rates and customer demand; state and federal rate regulations; political, legal and economic conditions and developments in the United States; the performance of projects undertaken by the non-traditional business and the success of efforts to invest in and develop new opportunities; 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 SOUTHERN or its subsidiaries; the effects of, and changes in, economic conditions in the areas in which SOUTHERN's subsidiaries operate; the direct or indirect effects on SOUTHERN's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and acceptance of SOUTHERN's new product and service offerings; the ability of SOUTHERN to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports filed from time to time with the SEC. iv PART I Item 1. BUSINESS SOUTHERN was incorporated under the laws of Delaware on November 9, 1945. SOUTHERN is domesticated under the laws of Georgia and is qualified to do business as a foreign corporation under the laws of Alabama. SOUTHERN owns all the outstanding common stock of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, each of which is an operating public utility company. The operating companies supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively. More particular information relating to each of the operating companies is as follows: ALABAMA is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company and Houston Power Company. The predecessor Alabama Power Company had had a continuous existence since its incorporation in 1906. GEORGIA was incorporated under the laws of the State of Georgia on June 26, 1930, and admitted to do business in Alabama on September 15, 1948. GULF is a corporation which was organized under the laws of the State of Maine on November 2, 1925, and admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984. MISSISSIPPI was incorporated under the laws of the State of Mississippi on July 12, 1972, was admitted to do business in Alabama on November 28, 1972, and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924, and was admitted to do business in Mississippi on December 23, 1924, and in Alabama on December 7, 1962. SAVANNAH is a corporation existing under the laws of the State of Georgia; its charter was granted by the Secretary of State on August 5, 1921. SOUTHERN also owns all the outstanding common stock of Southern LINC, Southern Nuclear, SCS, Southern Management Development (formerly Energy Solutions), Southern Telecom, Southern Power and other direct and indirect subsidiaries. Southern LINC provides digital wireless communications services to SOUTHERN's operating companies and also markets these services to the public within the Southeast. Southern Nuclear provides services to ALABAMA's and GEORGIA's nuclear plants. Southern Management Development focuses on new and existing programs to enhance customer satisfaction, efficiency and stockholder value. Southern Telecom provides wholesale fiber optic solutions to telecommunication providers in the Southeastern United States. In January 2001, SOUTHERN formed a new subsidiary, Southern Power. This subsidiary constructs, owns and manages wholesale generating assets in the Southeast. Southern Power will be the primary growth engine for SOUTHERN's competitive wholesale market-based energy business. ALABAMA and GEORGIA each own 50% of the outstanding common stock of SEGCO. SEGCO owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000 volt transmission lines extending from Plant Gaston to the Georgia state line at which point connection is made with the GEORGIA transmission line system. Reference is made to Note 12 to the financial statements of SOUTHERN in Item 8 herein for additional information regarding SOUTHERN's segment and related information. Mirant Corporation In April 2000, SOUTHERN announced an initial public offering of up to 19.9 percent of Mirant and its intentions to spin off the remaining ownership of Mirant to SOUTHERN stockholders within 12 months of the initial stock offering. On October 2, 2000, Mirant completed its initial public offering of 66.7 million I-1 shares of common stock priced at $22 per share. This represented 19.7 percent of the 338.7 million shares outstanding. As a result of the stock offering, SOUTHERN recorded a $560 million increase in paid-in capital with no gain or loss being recognized. On February 19, 2001, SOUTHERN's board of directors approved the spin off of its remaining ownership of 272 million Mirant shares. On April 2, 2001, the tax-free distribution of Mirant shares was completed at a ratio of approximately 0.4 for every share of SOUTHERN common stock held at record date. The distribution resulted in charges of approximately $3.2 billion and $0.4 billion to SOUTHERN's paid-in capital and retained earnings, respectively. As a result of the spin off, SOUTHERN's financial statements reflect Mirant's results of operations, balance sheets and cash flows as discontinued operations. The SOUTHERN System Operating Companies The transmission facilities of each of the operating companies are connected to the respective company's own generating plants and other sources of power and are interconnected with the transmission facilities of the other operating companies and SEGCO by means of heavy-duty high voltage lines. (In the case of GEORGIA's integrated transmission system, see Item 1 - BUSINESS - "Territory Served by the Operating Companies" herein.) Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. Additionally, the operating companies have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy Corporation, South Carolina Electric & Gas Company and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations and other matters affecting the reliability of bulk power supply. The operating companies have joined with other utilities in the Southeast (including those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the operating companies are represented on the National Electric Reliability Council. An intra-system interchange agreement provides for coordinating operations of the power producing facilities of the operating companies and the capacities available to such companies from non-affiliated sources and for the pooling of surplus energy available for interchange. Coordinated operation of the entire interconnected system is conducted through a central power supply coordination office maintained by SCS. The available sources of energy are allocated to the operating companies to provide the most economical sources of power consistent with good operation. The resulting benefits and savings are apportioned among the operating companies. SCS has contracted with SOUTHERN, each operating company, various of the other subsidiaries, Southern Nuclear, Southern Power and SEGCO to furnish, at cost and upon request, the following services: general executive and advisory services, power pool operations, general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pensions, corporate, rates, budgeting, public relations, human resources, systems and procedures and other services with respect to business and operations and power pool operations. Southern Management Development and Southern LINC have also secured from the operating companies certain services which are furnished at cost. Southern Nuclear has contracts with ALABAMA to operate the Farley Nuclear Plant, and with GEORGIA to operate Plants Hatch and Vogtle. See Item 1 - BUSINESS - "Regulation - Atomic Energy Act of 1954" herein. Southern Power As stated above, Southern Power will be the primary growth engine for SOUTHERN's competitive wholesale market-based energy business. Southern Power intends to sell the output of its generating assets under long-term, market-based contracts I-2 both to unaffiliated wholesale purchasers as well as the operating companies (under power purchase agreements approved by the respective public service commissions). Southern Power's wholesale generating assets will not be placed in the operating companies' rate bases, and Southern Power will only be able to recover costs from the operating companies based on the terms of the market-based contracts for its wholesale generating assets. The market-based contracts typically pass the cost of fuel to the wholesale energy purchasers and reduce Southern Power's business risks, but its overall profit will depend on the parameters of the wholesale market and its efficient operation of its wholesale generating assets. By the end of 2003, Southern Power plans to have approximately 4,700 megawatts of generating capacity in commercial operation. At December 31, 2001, 800 megawatts were in commercial operation and some 3,900 megawatts of capacity are under construction. Other Business In March 2001, Energy Solutions changed its name to Southern Management Development. Southern Management Development then created a separate entity, Southern Company Energy Solutions LLC (SCES LLC) for its energy business. SCES LLC provides energy related services such as energy outsourcing, energy conservation, facility maintenance, energy management and turnkey services for industrial, commercial, and governmental customers. Southern Management Development focuses on new and existing programs to enhance customer satisfaction, efficiency and stockholder value. Examples are: Bill Payment Protection, an insurance product that protects a residential customer by paying the electric bill in the event the customer becomes involuntarily unemployed, disabled or goes on unpaid leave; and Electric Vehicle Chargers, a program to supply electric vehicle charging units to industrial customers. In 1996, Southern LINC began serving SOUTHERN's operating companies and marketing its services to non-affiliates within the Southeast. Its system covers approximately 127,000 square miles and combines the functions of two-way radio dispatch, cellular phone, short text and numeric messaging and wireless data transfer. These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of rate-regulated operations. However, these activities also involve a higher degree of risk. SOUTHERN expects to make substantial investments over the period 2002-2004 in these and other new businesses. In 1999, MESH, a subsidiary of SOUTHERN, filed a petition for Chapter 11 bankruptcy relief in the U.S. Bankruptcy Court. On August 4, 2000, MESH filed a proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed plan of reorganization was most recently amended on October 15, 2001. SOUTHERN expects that approval of a plan of reorganization would result in either a termination of SOUTHERN's ownership interest in MESH or the exchange of all assets of MESH for the cancellation of securities held by the bondholders, but would not affect SOUTHERN's continuing guarantee obligations. Reference is made to Item 3 - "Legal Proceedings" herein for additional information relating to this matter. Certain Factors Affecting the Industry Various factors are currently affecting the electric utility industry in general, including increasing competition and the regulatory changes related thereto, costs required to comply with environmental regulations and the potential for new business opportunities (with their associated risks) outside of traditional rate-regulated operations. The effects of these and other factors on the SOUTHERN system are described herein. Particular reference is made to Item 1 - BUSINESS - "Other Business", "Competition" and "Environmental Regulation." See also "Cautionary Statement Regarding Forward-Looking Information." In December 1999, the FERC issued its final rule on RTOs. The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. SOUTHERN has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, SOUTHERN explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In January 2002, the sponsors of SeTrans held a public meeting to form a I-3 Stakeholder Advisory Committee, which will participate in the development of the RTO. SOUTHERN continues to work with the other sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to have a material impact on SOUTHERN's financial statements. The outcome of this matter cannot now be determined. Construction Programs The subsidiary companies of SOUTHERN are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Construction additions or acquisitions of property during 2002 through 2004 by the operating companies, SEGCO, SCS, Southern LINC, Southern Power and other subsidiaries are estimated as follows: (in millions) ------------------------------ -------- --------- ---------- 2002 2003 2004 -------- --------- ---------- ALABAMA $ 671 $ 592 $673 GEORGIA 971 752 809 GULF 103 72 107 MISSISSIPPI 84 72 85 SAVANNAH 35 38 43 SEGCO 15 17 23 SCS 27 23 25 Southern LINC 29 28 23 Southern Power 834 488 473 Other 29 14 2 --------------------------- ----------- --------- ---------- SOUTHERN system $2,798 $2,096 $ 2,263 =========================== =========== ========= ========== I-4
Estimated construction costs in 2002 are expected to be apportioned approximately as follows: (in millions) ---------------------------- --------------- --------------- ------------- --------- --------------- ---------------- ------------ SOUTHERN Southern system* ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH Power --------------- --------------- ------------- --------- --------------- ---------------- ------------ New generation $ 833 $ - $ - $24 $- $- $809 Other generating facilities including associated plant substations 703 248 383 24 25 8 - New business 365 127 182 23 15 18 - Transmission 378 141 210 9 16 2 - Joint line and substation 55 - 45 7 3 - - Distribution 162 68 61 10 17 6 - Nuclear fuel 123 63 60 - - - - General plant 179 24 30 6 8 1 25 --------------- --------------- ------------- --------- --------------- ---------------- ------------ $2,798 $671 $971 $103 $84 $35 $834 =============== =============== ============= ========= =============== ================ ============
* SCS, Southern LINC and other businesses plan capital additions to general plant in 2002 of $27 million, $29 million and $29 million, respectively, while SEGCO plans capital additions of $15 million to generating facilities. (See Item 1 - BUSINESS - "Other Business" herein.) The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisitions of additional generating assets; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; increasing costs of labor, equipment and materials; and cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. SOUTHERN has approximately 4,500 megawatts of new generating capacity scheduled to be placed in service by 2003. Approximately 3,900 megawatts of additional new capacity will be dedicated to the wholesale market and owned by Southern Power. Significant construction of transmission and distribution facilities and upgrading of generating plants will be continuing. Under Georgia law, GEORGIA and SAVANNAH each are required to file an Integrated Resource Plan for approval by the Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the construction of new power plants and new purchase power contracts. (See Item 1 - BUSINESS - "Rate Matters - Integrated Resource Planning" herein.) See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein for information with respect to certain existing and proposed environmental requirements and Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein for additional information concerning ALABAMA's, GEORGIA's and Southern Power's joint ownership of certain generating units and related facilities with certain non-affiliated utilities. I-5 Financing Programs The amount and timing of additional equity capital to be raised in 2002, as well as in subsequent years, will be contingent on SOUTHERN's investment opportunities. Equity capital can be provided from any combination of public offerings, private placements or SOUTHERN's stock plans. The operating companies plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from internal sources and by the issuances of new debt and preferred equity securities, term loans and short-term borrowings. However, the type and timing of any financings -- if needed -- will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt and trust preferred securities. Southern Power will use both external funds and equity capital from SOUTHERN to finance its construction program. In addition, Southern Power has an $850 million revolving credit facility which extends through November 2004. Short-term debt is often utilized as appropriate at SOUTHERN, the operating companies, SEGCO and Southern Power. The maximum amounts of short-term and term-loan indebtedness authorized by the appropriate regulatory authorities are shown on the following table: Amount Outstanding at Authorized December 31, 2001 -------------- --------------------- (in millions) ALABAMA $1,000(1) $ 10 GEORGIA 1,700(2) 748 GULF 300(1) 87 MISSISSIPPI 350(1) 16 SAVANNAH 205(2) 32 Southern Power 2,500(3) 1 SOUTHERN 2,000(1) 950 ------------------- ------------- -- ------------------- Notes: (1) ALABAMA's authority is based on authorization received from the Alabama PSC, which expires December 31, 2003. No SEC authorization is required for ALABAMA. GULF, MISSISSIPPI and SOUTHERN have received SEC authorization to issue from time to time short-term and/or term-loan notes to banks and commercial paper to dealers in the amounts shown through December 31, 2003, December 31, 2002 and December 31, 2004, respectively. (2) GEORGIA and SAVANNAH have received SEC authorization to issue from time to time short-term and term-loan notes to banks and commercial paper to dealers in the amounts shown through December 31, 2002. Authorization for term-loan indebtedness is also required by the Georgia PSC. SAVANNAH received authority from the Georgia PSC for $115 million in term loans expiring December 31, 2003. As a part of a financing request from the Georgia PSC, GEORGIA has asked for financing authority of $1.765 billion in term loans. (3) Southern Power has been authorized by the SEC to enter into various financing arrangements, including short-term loans, through June 30, 2005, which in the aggregate may not exceed $2.5 billion. Reference is made to Note 8 to the financial statements for SOUTHERN, Note 8 to the financial statements for ALABAMA, GULF and MISSISSIPPI and Note 6 to the financial statements for SAVANNAH and Note 9 to the financial statements for GEORGIA in Item 8 herein for information regarding the registrants' bank credit arrangements. I-6 Fuel Supply The operating companies' and SEGCO's supply of electricity is derived predominantly from coal. The sources of generation for the years 1999 through 2001 are shown below: Oil and ALABAMA Coal Nuclear Hydro Gas --------- ---------- --------- --------- 1999 72 20 5 3 2000 72 19 3 6 2001 64 18 6 12 GEORGIA 1999 75 22 1 2 2000 76 21 1 2 2001 75 23 1 1 GULF 1999 97 ** ** 3 2000 98 ** ** 2 2001 99 ** ** 1 MISSISSIPPI 1999 81 ** ** 19 2000 83 ** ** 17 ** 2001 59 ** ** 41 SAVANNAH 1999 78 ** ** 22 2000 88 ** ** 12 2001 93 ** ** 7 SEGCO 1999 100 ** ** * 2000 100 ** ** * 2001 100 ** ** * SOUTHERN system*** 1999 78 17 2 3 2000 78 16 2 4 2001 72 16 3 9 ---------- ------- --------- ---------- --------- --------- *Less than 0.5%. **Not applicable. *** Amounts shown for the SOUTHERN system are weighted averages of the operating companies, Southern Power and SEGCO. The average costs of fuel in cents per net kilowatt-hour generated for 1999 through 2001 are shown below: 1999 2000 2001 -------------- ------------- ------------- ALABAMA 1.44 1.54 1.56 GEORGIA 1.34 1.39 1.38 GULF 1.60 1.68 1.76 MISSISSIPPI 1.65 1.80 1.89 SAVANNAH 2.20 2.28 2.16 SEGCO 1.77 1.51 1.44 SOUTHERN System* 1.45 1.51 1.56 ------------------- -------------- ------------- ------------- * Amounts shown for the SOUTHERN system are weighted averages of the operating companies, Southern Power and SEGCO. I-7 The operating companies have long-term agreements in place from which they expect to receive approximately 78% of their coal burn requirements in 2002. These agreements cover remaining terms up to 9 years. In 2001, the weighted average sulfur content of all coal burned by the operating companies was 0.76% sulfur. This sulfur level, along with banked sulfur dioxide allowances, allowed the operating companies to remain within limits as set forth by Phase II of the Clear Air Act. As more and more strict environmental regulations are proposed that impact the utilization of coal, the fuel mix will be monitored to insure that sufficient quantities of the proper type of coal or natural gas are in place to remain in compliance with applicable laws and regulations. See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein. The operating companies and Southern Power also have long-term agreements in place for their natural gas burn requirements. For 2002, the operating companies and Southern Power have contracted for 163.6 billion cubic feet of natural gas supply. These agreements cover remaining terms up to 5 years. In addition to gas supply, the operating companies have contracts in place for both firm gas transportation and firm gas storage. Management believes that these contracts provide sufficient natural gas supplies, transportation and storage to ensure normal operations of the SOUTHERN system's natural gas generating units. Changes in fuel prices are generally reflected in fuel adjustment clauses contained in rate schedules. See Item 1 - BUSINESS - "Rate Matters - Rate Structure" herein. ALABAMA and GEORGIA have numerous contracts covering a portion of their nuclear fuel needs for uranium, conversion services, enrichment services and fuel fabrication. These contracts have varying expiration dates and most are short to medium term (less than 10 years). Management believes that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment of normal operations of the SOUTHERN system's nuclear generating units. ALABAMA and GEORGIA have contracts with the DOE that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in January 1998, as required by the contracts, and the companies are pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity is available at Plant Farley to maintain full-core discharge capability until the refueling outages scheduled for 2006 and 2008 for units 1 & 2, respectively. Sufficient pool storage capacity currently for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. To maintain pool discharge capability at Plant Hatch, effective June 2000, an on-site dry storage facility became operational. Sufficient dry storage capacity is believed to be available to continue dry storage operations at Plant Hatch through the life of the plant. Procurement of on-site dry storage capacity at Plant Vogtle will begin in sufficient time to maintain pool full-core discharge capability. The Energy Act required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants, including ALABAMA and GEORGIA. This assessment is being paid over a 15-year period which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. Territory Served by the Operating Companies The territory in which the operating companies provide electric service comprises most of the states of Alabama and Georgia together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems which obtain some or all of their power requirements either directly or indirectly from the operating companies. The territory has an area of approximately 120,000 square miles and an estimated population of approximately 11 million. ALABAMA is engaged, within the State of Alabama, in the generation and purchase of electricity and the distribution and sale of such electricity at retail in over 1,000 communities (including Anniston, Birmingham, Gadsden, Mobile, Montgomery and Tuscaloosa) and at wholesale to 15 municipally-owned electric distribution systems, 11 of which are served indirectly through sales to AMEA, and two rural distributing cooperative associations. ALABAMA also I-8 supplies steam service in downtown Birmingham. ALABAMA also sells, and cooperates with dealers in promoting the sale of, electric appliances. GEORGIA is engaged in the generation and purchase of electricity and the distribution and sale of such electricity within the State of Georgia at retail in over 600 communities, as well as in rural areas, and at wholesale currently to OPC, MEAG, Dalton and the City of Hampton. GULF is engaged, within the northwestern portion of Florida, in the generation and purchase of electricity and the distribution and sale of such electricity at retail in 71 communities (including Pensacola, Panama City and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility and a municipality. MISSISSIPPI is engaged in the generation and purchase of electricity and the distribution and sale of such energy within the 23 counties of southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations and one generating and transmitting cooperative. SAVANNAH is engaged, within a five-county area in eastern Georgia, in the generation and purchase of electricity and the distribution and sale of such electricity at retail and, as a member of the SOUTHERN system power pool, the transmission and sale of wholesale energy. For information relating to kilowatt-hour sales by classification for each registrant, reference is made to "Management's Discussion and Analysis-Results of Operations" in Item 7 herein. Also, for information relating to the sources of revenues for the SOUTHERN system and each of the operating companies, reference is made to Item 6 herein. A portion of the area served by the operating companies adjoins the area served by TVA and its municipal and cooperative distributors. An Act of Congress limits the distribution of TVA power, unless otherwise authorized by Congress, to specified areas or customers which generally were those served on July 1, 1957. The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. There are 71 electric cooperative organizations operating in the territory in which the operating companies provide electric service at retail or wholesale. One of these, AEC, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems and other customers in south Alabama and northwest Florida. AEC owns generating units with approximately 840 megawatts of nameplate capacity, including an undivided ownership interest in ALABAMA's Plant Miller Units 1 and 2. AEC's facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from AEC to the extent such energy is available. Two of the 14 distributing cooperatives operating in ALABAMA's service territory obtain a portion of their power requirements directly from ALABAMA. Four electric cooperative associations, financed by the RUS, operate within GULF's service area. These cooperatives purchase their full requirements from AEC and SEPA (a federal power marketing agency). A non-affiliated utility also operates within GULF's service area and purchases its full requirements from GULF. ALABAMA and GULF have entered into separate agreements with AEC involving interconnection between the respective systems. The delivery of capacity and energy from AEC to certain distributing cooperatives in the service areas of ALABAMA and GULF is governed by the SOUTHERN/AEC Network Transmission Service Agreement. The rates for this service to AEC are based on the negotiated agreement on file with the FERC. See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein for details of ALABAMA's joint-ownership with AEC of a portion of Plant Miller. MISSISSIPPI has an interchange agreement with SMEPA, a generating and transmitting cooperative, pursuant to which various services are provided, including the furnishing of protective capacity by MISSISSIPPI to SMEPA. SMEPA has a generating capacity of 1,947 megawatts and a transmission system estimated to be 1,549 miles in length. I-9 There are 43 electric cooperative organizations operating in, or in areas adjoining, territory in the State of Georgia in which GEORGIA provides electric service at retail or wholesale. Three of these organizations obtain their power from TVA and one from other sources. OPC has a wholesale power contract with the remaining 39 of these cooperative organizations. OPC utilizes self-owned generation acquired from GEORGIA, megawatt capacity purchases from GEORGIA under power supply agreements, and other arrangements to meet its power supply obligations. Pursuant to the latest agreement entered into in April 1999, OPC will purchase 250 megawatts of steam capacity through March 2006. There are 65 municipally-owned electric distribution systems operating in the territory in which the operating companies provide electric service at retail or wholesale. AMEA was organized under an act of the Alabama legislature and is comprised of 11 municipalities. In 1986, ALABAMA entered into a firm power sales contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum of 100 megawatts) for a period of 15 years (1986 Contract). In October 1991, ALABAMA entered into a second firm power purchase contract with AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80 megawatts) for a period of 15 years (1991 Contract). Under the terms of the contracts, ALABAMA received payments from AMEA representing the net present value of the revenues associated with the respective capacity entitlements. The 1986 Contract expired in July 2001, however, the payments for the 1991 Contract will continue as scheduled capacity is made available over the terms of the 1991 Contract. See Note 6 to ALABAMA's financial statements in Item 8 herein for further information on these contracts. Forty-eight municipally-owned electric distribution systems and one county-owned system receive their requirements through MEAG, which was established by a state statute in 1975. MEAG serves these requirements from self-owned generation facilities acquired from GEORGIA, power purchased from GEORGIA and purchases from other resources. In August 1997, a pseudo scheduling and services agreement was implemented between GEORGIA and MEAG that replaced the partial requirements tariff pursuant to which GEORGIA previously sold wholesale energy to MEAG. Since 1977, Dalton has filled its requirements from self-owned generation facilities acquired from GEORGIA and through purchases from GEORGIA pursuant to their partial requirements tariff. One municipally-owned electric distribution system's full requirements are served under a market-based contract by GEORGIA. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) GEORGIA has entered into substantially similar agreements with Georgia Transmission Corporation (formerly OPC's transmission division), MEAG and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of each. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) SCS, acting on behalf of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, also has a contract with SEPA providing for the use of those companies' facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain United States government hydroelectric projects. The retail service rights of all electric suppliers in the State of Georgia are regulated by the 1973 State Territorial Electric Service Act. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein on March 29, 1973 (451 municipalities, including Atlanta, Columbus, Macon, Augusta, Athens, Rome and Valdosta, to GEORGIA; 115 to electric cooperatives; and 50 to publicly-owned systems). Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in the Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, the Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 kilowatts may receive electric service from the supplier of its choice. (See also Item 1 - BUSINESS - "Competition" herein.) I-10 Under and subject to the provisions of its franchises and concessions and the 1973 State Territorial Electric Service Act, SAVANNAH has the full but nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale, Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee Island, Springfield, Thunderbolt and Vernonburg, and in conjunction with a secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and Screven Counties by the Georgia PSC. (See also Item 1 - BUSINESS - "Competition" herein.) Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather Certificates" of public convenience and necessity to MISSISSIPPI and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by MISSISSIPPI, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 300,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a "Grandfather Certificate," the utility holding such certificate may, without further certification, extend its lines up to five miles; other extensions within that area by such utility, or by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate which are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC. Long-Term Power Sales and Lease Agreements The operating companies have long-term contractual agreements for the sale and lease of capacity to certain non-affiliated utilities located outside the SOUTHERN system service area. These agreements are firm and related to specific generating units. Because the energy is generally provided at cost under these agreements, profitability is primarily affected by capacity revenues. Unit power from specific generating plants is currently being sold to FP&L, FPC and JEA. Under these agreements, approximately 1,500 megawatts of capacity is scheduled to be sold annually unless reduced by FP&L, FPC and JEA for the periods after 2001 with a minimum of three years notice, until the expiration of the contracts in 2010. Southern Power and MISSISSIPPI have operating leases for portions of their generating unit capacity. Reference is made to Note 5 to the financial statements for SOUTHERN; Note 6 to the financial statements for ALABAMA, GULF and MISSISSIPPI and Note 7 to the financial statements for GEORGIA in Item 8 herein for additional information regarding contracts for the sales and lease of capacity and energy to non-territorial customers. Competition The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Act. The Energy Act allows IPPs to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it has been a major catalyst for the recent restructuring and consolidations taking place within the utility industry. Numerous federal and state initiatives are in varying stages that promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Alabama, Florida, Georgia and Mississippi, none have been enacted. Enactment would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced and I-11 other issues related to the energy crisis that occurred in California. As a result of that crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. Reference is made to Item 1 - BUSINESS - "Certain Factors Affecting the Industry" herein for information relating to SOUTHERN's RTO filing with the FERC. Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if SOUTHERN's electric utilities do not remain low-cost producers and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings. Reference is made to ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, "Management's Discussion and Analysis - Future Earnings Potential" in Item 7 herein for further discussion of rate matters. To adapt to a less regulated, more competitive environment, SOUTHERN continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, acquisitions involving other utility or non-utility businesses or properties, internal restructuring, disposition of certain assets or some combination thereof. Furthermore, SOUTHERN may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations and financial condition of SOUTHERN. (See Item 1 - BUSINESS - "Southern Power" and "Other Business" herein.) As a result of the foregoing factors, SOUTHERN has experienced increasing competition for available off-system sales of capacity and energy from neighboring utilities and alternative sources of energy. Additionally, the future effect of cogeneration and small-power production facilities on the SOUTHERN system cannot currently be determined but may be adverse. SOUTHERN is working to maintain and expand its share of wholesale energy sales in the Southeastern power markets. In January 2001, SOUTHERN formed a new subsidiary - Southern Power. This subsidiary constructs, owns and manages wholesale generating assets in the Southeast. Southern Power will be the primary growth engine for SOUTHERN's competitive wholesale market-based energy business. By the end of 2003, Southern Power plans to have approximately 4,700 megawatts of generating capacity in commercial operation. At December 31, 2001, 800 megawatts were in commercial operation and some 3,900 megawatts of capacity are under construction. ALABAMA currently has cogeneration contracts in effect with 10 industrial customers. Under the terms of these contracts, ALABAMA purchases excess generation of such companies. During 2001, ALABAMA purchased approximately 154 million kilowatt-hours from such companies at a cost of $5.5 million. GEORGIA currently has contracts in effect with nine small power producers whereby GEORGIA purchases their excess generation. During 2001, GEORGIA purchased 13.6 million kilowatt-hours from such companies at a cost of $355,000. GEORGIA has purchased power agreements for electricity with two cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2001, GEORGIA purchased 621.7 million kilowatt-hours at a cost of $52.3 million from these facilities. Reference is made to Note 4 to the financial statements for GEORGIA in Item 8 herein for information regarding purchased power commitments. GULF currently has agreements in effect with four industrial customers pursuant to which GULF purchases "as available" energy from customer-owned generation. During 2001, GULF purchased 114 million kilowatt-hours from such companies for $3.4 million. SAVANNAH currently has cogeneration contracts in effect with four large customers. Under the terms of these contracts, SAVANNAH purchases excess generation of such companies. During 2001, SAVANNAH purchased 41.2 million kilowatt-hours from such companies at a cost of $1.4 million. The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements and reliability. These factors are, in turn, affected by, among other influences, regulatory, political and environmental considerations, taxation and supply. I-12 The operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees as the result of self-generation (as described above) and fuel switching by customers and other factors. (See also Item 1 - BUSINESS - "Territory Served by the Operating Companies" herein for information concerning suppliers of electricity operating within or near the areas served at retail by the operating companies.) Regulation State Commissions The operating companies are subject to the jurisdiction of their respective state regulatory commissions, which have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC) and, in the cases of the Georgia PSC and Mississippi PSC, in part, retail service territories. (See Item 1 - BUSINESS - "Rate Matters" and "Territory Served by the Operating Companies" herein.) Holding Company Act SOUTHERN is registered as a holding company under the Holding Company Act, and it and its subsidiary companies are subject to the regulatory provisions of said Act, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, services performed by SCS and Southern Nuclear and the activities of certain of SOUTHERN's other subsidiaries. While various proposals have been introduced in Congress regarding the Holding Company Act, the prospects for legislative reform or repeal are uncertain at this time. Federal Power Act The Federal Power Act subjects the operating companies, Southern Power and SEGCO to regulation by the FERC as companies engaged in the transmission or sale at wholesale of electric energy in interstate commerce, including regulation of accounting policies and practices. ALABAMA and GEORGIA are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. Among the hydroelectric projects subject to licensing by the FERC are 14 existing ALABAMA generating stations having an aggregate installed capacity of 1,593,600 kilowatts and 18 existing GEORGIA generating stations having an aggregate installed capacity of 1,074,696 kilowatts. GEORGIA started the relicensing process for the Middle Chattahoochee Project in 1998. This project consists of the Goat Rock, Oliver and North Highlands facilities. GEORGIA and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity which began commercial operation in 1995. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) Licenses for all projects, excluding those discussed above, expire in the period 2007-2033 in the case of ALABAMA's projects and in the period 2005-2039 in the case of GEORGIA's projects. Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property taken, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property taken. Atomic Energy Act of 1954 ALABAMA, GEORGIA and Southern Nuclear are subject to the provisions of the Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over the construction and operation of nuclear reactors, particularly with regard to certain public health and safety and antitrust matters. The National Environmental Policy Act has been construed to expand the jurisdiction of the NRC to consider the environmental impact of a facility licensed under the Atomic Energy Act of 1954, as amended. I-13 NRC operating licenses currently expire in June 2017 and March 2021 for Plant Farley units 1 and 2, respectively, and in January 2027 and February 2029 for Plant Vogtle units 1 and 2, respectively. In January 2002, the NRC granted GEORGIA 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. Reference is made to Notes 1 and 10 to SOUTHERN's financial statements, Notes 1 and 9 to ALABAMA's financial statements and Notes 1 and 5 to GEORGIA's financial statements in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance. Additionally, Note 3 to GEORGIA's financial statements contains information regarding nuclear performance standards imposed by the Georgia PSC that may impact retail rates. Environmental Regulation The operating companies' and SEGCO's operations are subject to federal, state and local environmental requirements which, among other things, control emissions of particulates, sulfur dioxide and nitrogen oxides into the air; the use, transportation, storage and disposal of hazardous and toxic waste; and discharges of pollutants, including thermal discharges, into waters of the United States. The operating companies and SEGCO expect to comply with such requirements, which generally are becoming increasingly stringent, through technical improvements, the use of appropriate combinations of low-sulfur fuel and chemicals, addition of environmental control facilities, changes in control techniques and reduction of the operating levels of generating facilities. Failure to comply with such requirements could result in the complete shutdown of individual facilities not in compliance as well as the imposition of civil and criminal penalties. In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act - the acid rain compliance provision of the law - significantly affected SOUTHERN. Reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995. SOUTHERN achieved Phase I compliance at its affected plants by primarily switching to low-sulfur coal and with some equipment upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $300 million. Phase II sulfur dioxide compliance was required in 2000. SOUTHERN used emission allowances and fuel switching to comply with Phase II requirements. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment requirements increased total construction expenditures through 2000 by approximately $100 million. Respective state plans to address the one-hour ozone non-attainment standards for the Atlanta and Birmingham areas have been established and must be implemented in May 2003. Seven generating plants in the Atlanta area and two plants in the Birmingham area will be affected. Construction expenditures for compliance with these new rules are currently estimated at approximately $940 million, of which $520 million remains to be spent. A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provision. However, there can be no assurance that all Clean Air Act costs will be recovered. In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals is considering other legal challenges to these standards. A court decision is expected in the spring of 2002. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued regional nitrogen oxide reduction rules to the states for implementation. The final rule affects 21 states, including Alabama and Georgia. Compliance is required by May 31, 2004, for most states, including Alabama. For Georgia, further rulemaking was required, and proposed I-14 compliance was delayed until May 1, 2005. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $190 million. In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clear Air Act, and the regulations are scheduled to be finalized by the end of 2004 with implementation to take place around 2007. In January 2001, the EPA proposed guidance for the determination of Best Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls is expected to take place around 2010. Litigation of the Regional Haze Regulations, including the BART provisions, is ongoing in the Federal District of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002. Implementation of the final state rules for these initiatives could require substantial further reduction in nitrogen oxide and sulfur dioxide and reductions in mercury and other HAPS emission from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. In October 1997, the EPA issued regulations setting forth requirements for Compliance Assurance Monitoring in its state and federal operating permit programs. These regulations were amended by the EPA in March 2001 in response to a court order resolving challenges to the rules brought by environmental groups and the utility industry. Generally, this rule affects the operation and maintenance of electrostatic precipitators and could involve significant additional ongoing expense. The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. SOUTHERN must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the subsidiaries could incur substantial costs to clean up properties. The subsidiaries conduct studies to determine the extent of any required cleanup and have recognized in their respective financial statements costs to clean up known sites. These costs for SOUTHERN amounted to $1 million in 2001 and $4 million in both 2000 and 1999. Additional sites may require environmental remediation for which the subsidiaries may be liable for a portion or all required cleanup costs. Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include : the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of SOUTHERN's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect SOUTHERN. The impact of new legislation - if any - will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as a result of lawsuits alleging damages caused by electromagnetic fields. Reference is made to each registrant's "Management's Discussion and Analysis" in Item 7 herein for a discussion of the Clean Air Act and other environmental legislation and proceedings. Also see Item 3 - "Legal Proceedings", herein for information about a lawsuit brought on behalf of the EPA. The operating companies' and SEGCO's estimated capital expenditures for environmental quality control I-15 facilities for the years 2002, 2003 and 2004 are as follows: (in millions) ----------------------------------------------------------- 2002 2003 2004 --------------------------------- ALABAMA $157 $95 $112 GEORGIA 320 93 66 GULF 5 15 26 MISSISSIPPI 4 9 1 SAVANNAH 4 6 2 SEGCO * * * ---------------------------------------------------------- Total $490 $218 $207 =========================================================== * Amounts are less than $1 million. The foregoing estimates are included in the current construction programs. (See Item 1 - BUSINESS - "Construction Programs" herein.) Additionally, each operating company and SEGCO has incurred costs for environmental remediation of various sites. Reference is made to each registrant's "Management's Discussion and Analysis" in Item 7 herein for information regarding the registrants' environmental remediation efforts. Also, see Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for information regarding the identification of sites that may require environmental remediation by GEORGIA. The operating companies and SEGCO are unable to predict at this time what additional steps they may be required to take as a result of the implementation of existing or future quality control requirements for air, water and hazardous or toxic materials, but such steps could adversely affect system operations and result in substantial additional costs. The outcome of the matters mentioned above under "Regulation" cannot now be determined, except that these developments may result in delays in obtaining appropriate licenses for generating facilities, increased construction and operating costs, or reduced generation, the nature and extent of which, while not determinable at this time, could be substantial. Rate Matters Rate Structure The rates and service regulations of the operating companies are uniform for each class of service throughout their respective service areas. Rates for residential electric service are generally of the block type based upon kilowatt-hours used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers' rates are generally based upon usage by the customer including those with special features to encourage off-peak usage. Additionally, the operating companies are allowed by their respective PSCs to negotiate the terms and compensation of service to large customers. Such terms and compensation of service, however, are subject to final PSC approval. ALABAMA, GEORGIA and SAVANNAH are allowed by state law to recover fuel and net purchased energy costs through fuel cost recovery provisions which are adjusted to reflect increases or decreases in such costs. GULF recovers from retail customers costs of fuel, net purchased power, energy conservation and environmental compliance through provisions which are adjusted to reflect increases or decreases in such costs. GULF's recovery of these costs is based upon an annual projection - any over/under recovery during such period is reflected in a subsequent annual period with interest. With respect to MISSISSIPPI's retail rates, fuel and purchased power costs are billed to such customers under the fuel adjustment clause and energy costs management clause. The adjustment factors for MISSISSIPPI's retail and wholesale rates are generally levelized based on the estimated energy cost for the year, adjusted for any actual over/under collection from the previous year. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates. Rate Proceedings Reference is made to MISSISSIPPI's "Management's Discussion and Analysis" in Item 7 and to Note 3 to each registrant's financial statements in Item 8 herein for a discussion of rate matters. I-16 In February 2002, MISSISSIPPI reached an agreement with certain of its wholesale customers to increase its wholesale tariff rates effective June 2002. MISSISSIPPI filed the settlement agreement with the FERC on March 5, 2002. The FERC has 60 days to either set the issue for hearing with the proposed rates subject to refund or let the new rates go into effect as filed. The agreement results in an annual increase of approximately $10.5 million and the adoption of an Energy Cost Management Clause similar to the one approved by MISSISSIPPI's retail jurisdiction (see Note 1 to MISSISSIPPI's financial statements in Item 8 herein). In addition, MISSISSIPPI and its customers agreed that neither party would seek a unilateral change to the new rates prior to December 31, 2003, except for changes due to the operation of the fuel adjustment and energy cost management clauses. Though the FERC has accepted settlement agreements as filed in the past, the ultimate outcome of this matter before the FERC cannot now be determined. On March 5, 2002, the Alabama PSC approved a revision to ALABAMA's rates that provide for periodic adjustments based upon ALABAMA's earned return on end-of-period retail common equity. This revision provides for an annual, rather than quarterly, adjustment and imposes a 3 percent limit on any such annual adjustment. A 2 percent increase in retail rates will become effective in April 2002 in accordance with the Rate Stabilization Equalization Plan. The return on common equity range of 13.0 to 14.5 percent remains unchanged. The Alabama PSC also accepted ALABAMA's proposal to lower the energy cost recovery factor for the billing months April 2002 through December 2002. Integrated Resource Planning In July 2001, the Georgia PSC approved the GEORGIA and SAVANNAH 2001 Integrated Resource Plan, which was filed on January 31, 2001. The plans specify how GEORGIA and SAVANNAH each intends to meet the future electrical needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC must pre-certify these new resources. Once certified, all prudently incurred construction costs and purchase power costs will be recoverable through rates. In July 2001, the Georgia PSC approved GEORGIA's 2003/04 certification request, which was filed December 15, 2000, for approximately 1,800 megawatts of purchased power and 12 megawatts of upgraded hydro generation. This certification request included a seven-year PPA with Southern Power for two gas-fired combined cycle units that will be constructed at Plant Goat Rock. The first unit is designed to produce approximately 570 megawatts starting in 2003, with approximately 370 megawatts being available by June 2002. The second unit is designed to produce approximately 610 megawatts starting in 2004, with approximately 400 megawatts being available by June 2003. Also, a capacity upgrade of 12 megawatts was approved for the existing Goat Rock hydro units 1 and 2. In addition, this certification request included a seven-year PPA with Southern Power for a gas fired combined cycle generating unit to be constructed at Plant Autaugaville in Alabama. The unit is designed to produce approximately 610 megawatts starting in 2004. Based on an agreement with the Georgia PSC, the seven-year term of the PPA was modified to be 15 years. In April 2001, GEORGIA and SAVANNAH issued an RFP for their 2005/06 resource needs of approximately 2,500 megawatts. At the request of the Georgia PSC, this RFP requested all types of generation resources including coal and nuclear. The bids received from this RFP totaled more than 25,000 megawatts including over 1,800 megawatts of coal offers. As required by the Georgia PSC's 2001 IRP order, GEORGIA developed a self-build coal offer to be compared to the bid received through the RFP. In conjunction with the Georgia PSC, an economic analysis of the coal proposals was completed and the results indicated that the coal resources were not economical as compared to gas-fired generation at this point in time. Therefore, the Georgia PSC relieved GEORGIA of its obligation to continue to develop a coal self-build proposal. At the present time, the bids from this RFP are being analyzed and the best-cost projects will be selected. Once the PPAs have been completed for the selected projects, GEORGIA and SAVANNAH will file for certification of these PPAs by summer of 2002. GEORGIA and SAVANNAH expect the Georgia PSC to approve the certification request in the fall of 2002. I-17 Environmental Cost Recovery Plans In 1993, the Florida Legislature adopted legislation for an Environmental Cost Recovery Clause (ECRC), which allows a utility, including GULF, to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operation and maintenance expense, emission allowance expense, depreciation and a return on invested capital. In 1992, the Mississippi PSC approved MISSISSIPPI's Environmental Compliance Overview Plan (ECO Plan). The ECO Plan establishes procedures to facilitate the Mississippi PSC's overview of MISSISSIPPI's environmental strategy and provides for recovery of costs (including costs of capital associated with environmental projects approved by the Mississippi PSC). Under the ECO Plan, any increase in the annual revenue requirement is limited to 2 percent of retail revenues. However, the ECO Plan also provides for carryover of any amount over the 2 percent limit into the next year's revenue requirement. MISSISSIPPI conducts studies, when possible, to determine the extent of any required environmental remediation. Should such remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. MISSISSIPPI recovers such costs under the ECO Plan as they are incurred, as provided for in MISSISSIPPI's 1995 ECO Plan order. MISSISSIPPI filed its 2002 ECO Plan in January 2002, which, if approved as filed, will result in a slight increase in customer prices. Employee Relations The SOUTHERN system had a total of 26,122 employees on its payroll at December 31, 2001. -------------------------------------------------------------- Employees at December 31, 2001 ------------------------- ALABAMA 6,706 GEORGIA 9,048 GULF 1,309 MISSISSIPPI 1,316 SAVANNAH 550 SCS 3,569 Southern Nuclear 3,045 Other 579 -------------------------------------------------------------- Total 26,122 ============================================================== The operating companies have separate agreements with local unions of the IBEW generally covering wages, working conditions and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance and construction employees. ALABAMA has agreements with the IBEW on a three-year contract extending to August 14, 2005. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date. GEORGIA has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2002. GULF has an agreement with the IBEW on a three-year contract extending to August 15, 2005. MISSISSIPPI has an agreement with the IBEW on a four-year contract extending to August 16, 2002. SAVANNAH has four-year labor agreements with the IBEW and the Office and Professional Employees International Union that expire April 15, 2003 and December 1, 2003, respectively. Southern Nuclear has agreements with the IBEW on a five-year contract extending to August 15, 2006 for Plant Farley and a three-year contract extending to June 30, 2002 for Plants Hatch and Vogtle. Upon notice given at I-18 least 60 days prior to these dates, negotiations may be initiated with respect to agreement terms to be effective after such dates. Southern Nuclear is currently in negotiations with the Security, Police and Fire Professionals of America (formerly the United Plant Guard Workers of America) at Plant Hatch. The prior contract with the United Plant Guard Workers of America which extended to September 30, 2001 was not terminated, so the terms of the existing agreement have continued as negotiations of the new agreement continues. The parties will have the opportunity to terminate the agreement 60 days prior to October 1, 2002 if no agreement is reached prior to that time. The agreements also subject the terms of the pension plans for the companies discussed above to collective bargaining with the unions at five-year intervals. I-19 Item 2. PROPERTIES Electric Properties - The Electric Utilities The operating companies, Southern Power and SEGCO, at December 31, 2001, owned and/or operated 34 hydroelectric generating stations, 34 fossil fuel generating stations, three nuclear generating stations and five combined cycle/cogeneration stations. The amounts of capacity for each company are shown in the table below. ------------------------- ------------------------------------- Nameplate Generating Station Location Capacity (1) ------------------------- ------------------- ----------------- (Kilowatts) Fossil Steam Gadsden Gadsden, AL 120,000 Gorgas Jasper, AL 1,221,250 Barry Mobile, AL 1,525,000 Greene County Demopolis, AL 300,000 (2) Gaston Unit 5 Wilsonville, AL 880,000 Miller Birmingham, AL 2,532,288 (3) --------- ALABAMA Total 6,578,538 --------- Arkwright Macon, GA 160,000 Atkinson Atlanta, GA 180,000 Bowen Cartersville, GA 3,160,000 Branch Milledgeville, GA 1,539,700 Hammond Rome, GA 800,000 McDonough Atlanta, GA 490,000 McManus Brunswick, GA 115,000 Mitchell Albany, GA 170,000 Scherer Macon, GA 750,924 (4) Wansley Carrollton, GA 925,550 (5) Yates Newnan, GA 1,250,000 --------- GEORGIA Total 9,541,174 --------- Crist Pensacola, FL 1,045,000 Lansing Smith Panama City, FL 305,000 Scholz Chattahoochee, FL 80,000 Daniel Pascagoula, MS 500,000 (6) Scherer Unit 3 Macon, GA 204,500 (4) --------- GULF Total 2,134,500 --------- Eaton Hattiesburg, MS 67,500 Sweatt Meridian, MS 80,000 Watson Gulfport, MS 1,012,000 Daniel Pascagoula, MS 500,000 (6) Greene County Demopolis, AL 200,000 (2) ----------- MISSISSIPPI Total 1,859,500 ----------- ---------------------------------------------- ---------------- ------------------------- ----------------------------------------- Nameplate Generating Station Location Capacity ---------------------- ------------------------- ------------------ (Kilowatts) McIntosh Effingham County, GA 163,117 Kraft Port Wentworth, GA 281,136 Riverside Savannah, GA 102,278 ----------- SAVANNAH Total 546,531 ----------- Gaston Units 1-4 Wilsonville, AL SEGCO Total 1,000,000 (7) ----------- Total Fossil Steam 21,660,243 ----------- Nuclear Steam Farley Dothan, AL ALABAMA Total 1,720,000 ----------- Hatch Baxley, GA 899,612 (8) Vogtle Augusta, GA 1,060,240 (9) ----------- GEORGIA Total 1,959,852 ----------- Total Nuclear Steam 3,679,852 ----------- Combustion Turbines Greene County Demopolis, AL ALABAMA Total 720,000 ----------- Arkwright Macon, GA 30,580 Atkinson Atlanta, GA 78,720 Bowen Cartersville, GA 39,400 Intercession City Intercession City, FL 47,333 (10) McDonough Atlanta, GA 78,800 McIntosh Units 1,2,3,4,7,8 Effingham County, GA 480,000 McManus Brunswick, GA 481,700 Mitchell Albany, GA 118,200 Robins Warner Robins, GA 160,000 Wilson Augusta, GA 354,100 Wansley Carrollton, GA 26,322 (5) ----------- GEORGIA Total 1,895,155 ----------- Lansing Smith Unit A Panama City, FL 39,400 Pea Ridge Units 1-3 Pea Ridge, FL 14,250 ------ GULF Total 53,650 ------ Chevron Cogenerating Station Pascagoula, MS 147,292 (11) Sweatt Meridian, MS 39,400 Watson Gulfport, MS 39,360 --------- MISSISSIPPI Total 226,052 --------- ------------------------------------------------- ----------------- I-20 --------------------------- -------------------- ----------------- Nameplate Generating Station Location Capacity --------------------------- -------------------- ----------------- (Kilowatts) Boulevard Savannah, GA 59,100 Kraft Port Wentworth, GA 22,000 McIntosh Units 5&6 Effingham County, GA 160,000 ------- SAVANNAH Total 241,100 ------- Dahlberg 800,000 ------- Southern Power Total 800,000 ------- Gaston (SEGCO) Wilsonville, AL 19,680 (7) ----------- Total Combustion Turbines 3,955,637 ----------- Cogeneration Washington County Washington County, AL 123,428 GE Plastics Project Burkeville, AL 104,800 Theodore Theodore, AL 236,418 ----------- Total Cogeneration 464,646 ----------- Combined Cycle Barry Mobile, AL ALABAMA Total 1,070,424 --------- Daniel (Leased) Pascagoula, MS Mississippi Total 1,070,424 --------- Total Combined Cycle 2,140,848 --------- Hydroelectric Facilities Weiss Leesburg, AL 87,750 Henry Ohatchee, AL 72,900 Logan Martin Vincent, AL 128,250 Lay Clanton, AL 177,000 Mitchell Verbena, AL 170,000 Jordan Wetumpka, AL 100,000 Bouldin Wetumpka, AL 225,000 Harris Wedowee, AL 135,000 Martin Dadeville, AL 154,200 Yates Tallassee, AL 32,000 Thurlow Tallassee, AL 60,000 Lewis Smith Jasper, AL 157,500 Bankhead Holt, AL 54,000 Holt Holt, AL 46,000 ---------- ALABAMA Total 1,599,600 ---------- --------------------------- -------------------- ----------------- --------------------------- -------------------- ----------------- Nameplate Generating Station Location Capacity --------------------------- -------------------- ----------------- Barnett Shoals (Leased) Athens, GA 2,800 Bartletts Ferry Columbus, GA 173,000 Goat Rock Columbus, GA 26,000 Lloyd Shoals Jackson, GA 14,400 Morgan Falls Atlanta, GA 16,800 North Highlands Columbus, GA 29,600 Oliver Dam Columbus, GA 60,000 Rocky Mountain Rome, GA 215,256 (12) Sinclair Dam Milledgeville, GA 45,000 Tallulah Falls Clayton, GA 72,000 Terrora Clayton, GA 16,000 Tugalo Clayton, GA 45,000 Wallace Dam Eatonton, GA 321,300 Yonah Toccoa, GA 22,500 6 Other Plants 18,080 ----------- GEORGIA Total 1,077,736 ----------- Total Hydroelectric Facilities 2,677,336 ----------- Total Generating Capacity 34,578,562 =========== ------------------------------------------------ ----------------- Notes: (1) For additional information regarding facilities jointly-owned with non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein. (2) Owned by ALABAMA and MISSISSIPPI as tenants in common in the proportions of 60% and 40%, respectively. (3) Excludes the capacity owned by AEC. (4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for GULF is 25% of Unit 3. (5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity. (6) Represents 50% of the plant which is owned as tenants in common by GULF and MISSISSIPPI. (7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS herein.) (8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity. (9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity. (10) Capacity shown represents 33-1/3% of total plant capacity. GEORGIA owns a 1/3 interest in the unit with 100% use of the unit from June through September. FPC operates the unit. (11) Generation is dedicated to a single industrial customer. (12) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity. OPC operates the plant. I-21 Except as discussed below under "Titles to Property," the principal plants and other important units of the operating companies, Southern Power and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition. MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a forty-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2001, the unamortized portion of this cost was approximately $33.3 million. The all-time maximum demand on the operating companies and SEGCO was 31,359,000 kilowatts and occurred in August 2000. This amount excludes demand served by capacity retained by MEAG and Dalton and excludes demand associated with power purchased from OPC and SEPA by its preference customers. The reserve margin for the operating companies and SEGCO at that time was 8.1%. For additional information on peak demands, reference is made to Item 6 - SELECTED FINANCIAL DATA herein. ALABAMA and GEORGIA will incur significant costs in decommissioning their nuclear units at the end of their useful lives. (See Item 1 - BUSINESS - "Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and GEORGIA's financial statements in Item 8 herein.) Jointly-Owned Facilities ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in certain generating plants and other related facilities to or from non-affiliated parties. The percentages of ownership resulting from these transactions are as follows:
Total Percentage Ownership ---------------- -------- ------------ -------- --------- ------------ -------- Capacity ALABAMA AEC GEORGIA OPC MEAG DALTON FPC -------------- ---------------- -------- ------------ -------- --------- ------------ -------- (Megawatts) Units 1 and 2 1,320 91.8% 8.2% -% -% -% -% -% Plant Hatch 1,796 - - 50.1 30.0 17.7 2.2 - Plant Vogtle 2,320 - - 45.7 30.0 22.7 1.6 - Plant Scherer Units 1 and 2 1,636 - - 8.4 60.0 30.2 1.4 - Plant Wansley 1,779 - - 53.5 30.0 15.1 1.4 - Rocky Mountain 848 - - 25.4 74.6 - - - Intercession City, FL 142 - - 33.3 - - - 66.7 ----------------------------- -------------- -- ---------------- -------- ------------ -------- --------- ------------ --------
ALABAMA and GEORGIA have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain and Intercession City, as described below) as agent for the joint owners. In addition, GEORGIA has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG's bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the 1987 and 1990 write-offs of Plant Vogtle costs, the cost of such capacity and energy is included in purchased power from non-affiliates in GEORGIA's Statements of Income in Item 8 herein. I-22 Additional jointly-owned facilities also include Southern Power's 65% undivided interest in Stanton Unit A and related facilities jointly owned with the Orlando Utilities Commission, the Kissimmee Utility Authority and the Florida Municipal Power Agency. Currently under construction near Orlando, Florida, this project will be a 610 megawatt combined cycle unit and is scheduled for commerical operation in October 2003. Titles to Property The operating companies', Southern Power's and SEGCO's interests in the principal plants (other than certain pollution control facilities, one small hydroelectric generating station leased by GEORGIA, MISSISSIPPI's combined cycle units at Plant Daniel and the land on which five combustion turbine generators of MISSISSIPPI are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the liens of applicable mortgage indentures of ALABAMA, GULF, MISSISSIPPI and SAVANNAH and to excepted encumbrances as defined therein. The operating companies own the fee interests in certain of their principal plants as tenants in common. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) Properties such as electric transmission and distribution lines and steam heating mains are constructed principally on rights-of-way which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In substantially all of its coal reserve lands, SEGCO owns or will own the coal only, with adequate rights for the mining and removal thereof. I-23 Item 3. LEGAL PROCEEDINGS (1) United States of America v. ALABAMA (United States District Court for the Northern District of Alabama) On November 3, 1999, the EPA brought a civil action in the U.S. District Court in Georgia against ALABAMA. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to coal-fired generating facilities at ALABAMA's Plants Miller, Barry and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. On August 1, 2000, the U.S. District Court granted ALABAMA's motion to dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims against ALABAMA in federal district court in Birmingham, Alabama. ALABAMA's case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the TVA. The TVA case involves many of the same legal issues raised by the actions against ALABAMA. Because the outcome of the TVA case could have a significant adverse impact on ALABAMA, ALABAMA is party to that case as well. ALABAMA believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. (2) United States of America v. GEORGIA and SAVANNAH (United States District Court for the Northern District of Georgia) On November 3, 1999, the EPA brought a civil action in the U.S. District Court in Georgia against GEORGIA. The complaint alleges violation of the New Source Review provisions of the Clean Air Act with respect to coal-fired generating facilities at GEORGIA's Plants Bowen and Scherer. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. On March 27, 2001, the U.S. District Court granted the EPA's motion to amend its complaint to add the alleged violations at SAVANNAH's Plant Kraft and to add SAVANNAH as a defendant. The EPA concurrently issued a notice of violation relating to these two GEORGIA plants and SAVANNAH's Plant Kraft. The case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the TVA. The TVA case involves many of the same legal issues raised by the actions against GEORGIA and SAVANNAH. Because the outcome of the TVA case could have a significant adverse impact on GEORGIA and SAVANNAH, both GEORGIA and SAVANNAH are party to that case as well. GEORGIA and SAVANNAH believe that they complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. I-24 Item 3. LEGAL PROCEEDINGS (continued) (3) Cooper et al. v. GEORGIA, SOUTHERN, SCS and Energy Solutions (Superior Court of Fulton County, Georgia) On July 28, 2000, a lawsuit alleging race discrimination was filed by three GEORGIA employees against GEORGIA, SOUTHERN, and SCS in the Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit was removed to the United States District Court for the Northern District of Georgia. The lawsuit also raised claims on behalf of a purported class. The plaintiffs seek compensatory and punitive damages in an unspecified amount, as well as injunctive relief. On August 14, 2000, the lawsuit was amended to add four more plaintiffs. Also, an additional subsidiary of SOUTHERN, Energy Solutions (now Southern Management Development), was named a defendant. On October 11, 2001, the district court denied the plaintiffs' motion for class certification. The plaintiffs filed a motion to reconsider the order denying class certification, and the court denied the plaintiffs' motion to reconsider. On December 28, 2001, the plaintiffs filed a petition in the United States Court of Appeals for the Eleventh Circuit seeking permission to file an appeal of the October 11 decision. On March 15, 2002, the Eleventh Circuit denied the plaintiffs' petition; thus, the plaintiffs may not appeal the October 11 decision until the seven individual cases are resolved in the district court. Discovery on the seven named plaintiffs' individual claims that remain in the case is ongoing. The final outcome of the case cannot now be determined. (4) GEORGIA 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. In addition, in 1995 the EPA designated GEORGIA and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia that is listed on the federal National Priorities List. GEORGIA has contributed to the removal and remedial investigation and feasibility study costs for the site. Additional claims for recovery of natural resource damages at the site are anticipated. The final outcome of these matters cannot now be determined. Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein under the captions "Georgia Power Potentially Responsible Party Status" and "Other Environmental Contingencies," respectively. (5) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy Services Holdings, Inc. (U.S. Bankruptcy Court for the Southern District of Alabama). On August 4, 2000, MESH filed a proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed plan of reorganization was most recently amended on October 15, 2001. SOUTHERN expects that approval of a plan of reorganization would result in either a termination of SOUTHERN's ownership interest in MESH or the exchange of all assets of MESH for the cancellation of securities held by the bondholders, but would not affect SOUTHERN's continuing guarantee obligations. The final outcome of this matter cannot now be determined. Reference is made to Note 3 to SOUTHERN's financial statements in Item 8 herein under the caption "Mobile Energy Services' Petition for Bankruptcy." I-25 Item 3. LEGAL PROCEEDINGS (continued) (6) Gordon v. SOUTHERN et al. (United States District Court for the Southern District of California) and (7) Pier 23 Restaurant v. SOUTHERN et al. (United States District Court for the Northern District of California) Prior to the spin off of Mirant, SOUTHERN was named as a defendant in two lawsuits filed in the superior courts of California alleging that certain owners of electric generation facilities in California, including SOUTHERN, engaged in various unlawful and anticompetitive acts that served to manipulate wholesale power markets and inflate wholesale electricity prices in California. One lawsuit naming SOUTHERN, Mirant and other generators as defendants alleged that, as a result of the defendants' conduct, customers paid approximately $4 billion more for electricity that they otherwise would have and sought an award of treble damages, as well as other injunctive and equitable relief. The other suit likewise sought treble damages and equitable relief. The allegations in the two lawsuits in which SOUTHERN was named seemed to be directed to activities of subsidiaries of Mirant. On September 28 and November 6, 2001, the plaintiffs voluntarily dismissed SOUTHERN without prejudice from the two lawsuits in which it had been named as a defendant. Prior to being dismissed, SOUTHERN had notified Mirant of its claim for indemnification for costs associated with the lawsuits under the terms of the master separation agreement that governs the spin off of Mirant. Mirant had undertaken the defense of the lawsuits. Plaintiffs would not be barred by their own dismissal from naming SOUTHERN in some future lawsuit, but management believes that the likelihood of SOUTHERN having to pay damages in any such lawsuit is remote. See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation - Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's financial statements in Item 8 herein for a description of certain other administrative and legal proceedings discussed therein. Additionally, each of the operating companies, SCS, Southern Nuclear, Southern Power, Energy Solutions and Southern LINC are, in the normal course of business, engaged in litigation or administrative proceedings that include, but are not limited to, acquisition of property, injuries and damages claims, and complaints by present and former employees. I-26 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. ALABAMA ALABAMA held a special meeting of shareholders on November 21, 2001 for the purpose of amending its charter to effect certain changes in the Auction Procedures for ALABAMA's 1988 Auction Series Class A Preferred Stock and 1993 Auction Series Class A Preferred Stock. The amendment was passed and the vote tabulation was as follows: Votes ------------------------------------------------ For Against Abstain --- ------- ------- Common Stock 6,000,000 0 0 Preferred Stock 377,000 0 0 ---------- - - Total 6,377,000 0 0 ========= = = I-27 EXECUTIVE OFFICERS OF SOUTHERN (Identification of executive officers of SOUTHERN is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2001. H. Allen Franklin Chairman, President, Chief Executive Officer and Director Age 57 Elected Director in 1988 and Chief Executive Officer effective March 1, 2001. Previously served as President and Chief Operating Officer of SOUTHERN from June 1999 to March 2001; and as President and Chief Executive Officer of GEORGIA from January 1994 to June 1999. Dwight H. Evans Executive Vice President Age 53 Elected in 2001. Previously served as President and Chief Executive Officer of MISSISSIPPI from March 1995 to May 2001. David M. Ratcliffe Executive Vice President Age 53 Elected in 1999. He also has served as President and Chief Executive Officer of GEORGIA since June 1999. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of GEORGIA from March 1998 to June 1999; and as Senior Vice President of SOUTHERN from March 1995 to March 1998. Leonard J. Haynes Executive Vice President and Chief Marketing Officer Age 51 Elected in 2001. Previously served as Senior Vice President of GEORGIA from October 1998 to May 2001; and Vice President of GEORGIA from October 1992 to October 1998. G. Edison Holland, Jr. Executive Vice President Age 49 Elected in 2001. Previously served as President and Chief Executive Officer of SAVANNAH from 1997 until 2001. Gale E. Klappa Executive Vice President, Chief Financial Officer and Treasurer Age 51 Elected in 2001. Previously served as Financial Vice President, Chief Financial Officer and Treasurer form March 2001 to May 2001; Senior Vice President and Chief Strategic Officer of SOUTHERN from October 1999 to March 2001; President of Mirant's North America Group and Senior Vice President of Mirant from December 1998 to October 1999; and as President and Chief Executive Officer of Western Power Distribution, a subsidiary of Mirant located in Bristol, England, from September 1995 to December 1998. Charles D. McCrary Executive Vice President Age 50 Elected in 1998; serves as President and Chief Executive Officer of ALABAMA. Previously served as President and Chief Operating Officer of ALABAMA from May 2001 to October 2001; Vice President of SOUTHERN from February 1998 to April 2001; and as Executive Vice President of ALABAMA from 1994 through February 1998. W. Paul Bowers Age 44 Executive Vice President of SCS and President and Chief Executive Officer of Southern Power since May 2001. Previously served as Senior Vice President of SCS and Chief Marketing Officer of SOUTHERN from March 2000 to May 2001; President and Chief Executive Officer of Western Power Distribution, a subsidiary of Mirant located in Bristol, England, from December 1998 to 2000; and Senior Vice President of Retail Marketing for GEORGIA from 1995 to 1998. W. G. Hairston, III Age 57 President and Chief Executive Officer of Southern Nuclear since 1993. The officers of SOUTHERN were elected for a term running from the first meeting of the directors following the last annual meeting (May 23, 2001) for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified. I-28 EXECUTIVE OFFICERS OF ALABAMA (Identification of executive officers of ALABAMA is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2001. Elmer B. Harris Chairman and Director* Age 62 Elected in 1989. Served as President and Chief Executive Officer from 1989 to 2001. Elected Executive Vice President of SOUTHERN in 1991. Served as a Director of SOUTHERN since 1989. Charles D. McCrary President, Chief Executive Officer and Director Age 50 Elected in 2001. Served as President and Chief Operating Officer of ALABAMA from April 2001 to October 2001 and Vice President of SOUTHERN from February 1998 to April 2001. Previously served as Executive Vice President of External Affairs at ALABAMA from April 1994 through February 1998. William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer Age 58 Elected in 1991. Served as Treasurer since 1998 in addition to Executive Vice President and Chief Financial Officer since 1991. C. Alan Martin Executive Vice President Age 53 Elected in 1999. Served as Executive Vice President of External Affairs since January 2000. Previously served as Executive Vice President and Chief Marketing Officer for SOUTHERN from 1998 to 1999; and Vice President of Human Resources for SOUTHERN from May 1995 to March 1998. Steve R. Spencer Executive Vice President Age 46 Elected in 2001. Served as Senior Vice President of External Affairs from July 2000 to April 2001. Previously served as Vice President of SOUTHERN's external affairs organization from 1998 to 2001. Jerry L. Stewart Senior Vice President Age 52 Elected in 1999. Served as Senior Vice President of Fossil and Hydro Generation since 1999. Previously served as Vice President of SCS from 1992 to 1999. The officers of ALABAMA were elected for a term running from the last annual meeting of the directors (April 27, 2001) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. McCrary who was elected Chief Executive Officer on October 25, 2001. *Retired effective January 11, 2002. I-29 EXECUTIVE OFFICERS OF GEORGIA (Identification of executive officers of GEORGIA is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2001. David M. Ratcliffe President, Chief Executive Officer and Director Age 53 Elected as an Executive Officer in 1998 and as Director in 1999. Served as President and Chief Executive Officer since June 1999. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of GEORGIA from 1998 to 1999; and as Senior Vice President of SOUTHERN from March 1995 to March 1998. William C. Archer, III Executive Vice President Age 53 Elected in 1995. Served as Executive Vice President of External Affairs since 1995. Thomas A. Fanning Executive Vice President, Treasurer and Chief Financial Officer Age 44 Elected in 1999. Previously served as Senior Vice President of SCS and Chief Information Officer for SOUTHERN from March 1995 to June 1999. Judy M. Anderson Senior Vice President Age 53 Elected in 2001. Served as Senior Vice President of Charitable Giving since 2001. Previously served as Vice President and Corporate Secretary of GEORGIA from 1989 to 2001. Ronnie L. Bates Senior Vice President Age 47 Elected in 2001. Served as Senior Vice President, Marketing since 2001. Previously served as Vice President, Transmission from 2000 to 2001; and as General Manager, Transmission and Construction from 1995 to 2000. Mickey A. Brown Senior Vice President Age 54 Elected in 2001. Served as Senior Vice President of Distribution since 2001. Previously served as Vice President, Distribution from 2000 to 2001; and as Vice President, Northern Region from 1993 to 2000. James K. Davis Senior Vice President Age 61 Elected in 1993. Served as Senior Vice President of Corporate Relations since 1993, with Employee Relations being added to his responsibilities in 2000. Fred D. Williams Senior Vice President Age 57 Elected in 1992. Served as Senior Vice President of Resource Policy and Planning since 1997. Previously served as Senior Vice President of Wholesale Energy from 1995 to 1997. Leslie R. Sibert Vice President Age 39 Elected in 2001. Served as Vice President, Transmission since 2001. Previously served as Decatur Region Manager from 1999 to 2001; and as Assistant to Senior Vice President, Southern Wholesale Energy from 1996 to 1999. Christopher C. Womack Senior Vice President Age 43 Elected in 2001. Served as Senior Vice President of Fossil and Hydro since 2001. Previously served as Vice President and Chief People Officer of SOUTHERN from 1998 to 2001; and as Senior Vice President of Public Relations and Corporate Services at ALABAMA from 1995 to 1998. The officers of GEORGIA were elected for a term running from the last annual meeting of the directors (May 16, 2001) for one year until the next annual meeting or until their successors are elected and have qualified, except for Ms. Anderson, whose election was effective June 1, 2001; Mr. Bates, whose election was effective October 8, 2001; Ms. Sibert, whose election was effective November 14, 2001; and Mr. Womack, whose election was effective December 17, 2001. I-30 EXECUTIVE OFFICERS OF GULF (Identification of executive officers of GULF is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2001. Travis J. Bowden President, Chief Executive Officer and Director Age 63 Elected in 1994. Served as President and Chief Executive Officer since 1994. Francis M. Fisher, Jr. Vice President Age 53 Elected in 1989. Served as Vice President of Power Delivery and Customer Operations since 1996. John E. Hodges, Jr. Vice President Age 58 Elected in 1989. Served as Vice President of Marketing and Employee/External Affairs since 1996. Ronnie R. Labrato Vice President, Chief Financial Officer and Comptroller Age 48 Elected in 2000. Served as Vice President, Chief Financial Officer and Comptroller since 2001. Previously served as Comptroller and Chief Financial Officer from 2000 to 2001 and Controller from 1992 to 2000. Robert G. Moore Vice President Age 52 Elected in 1997. Served as Vice President of Power Generation and Transmission of GULF and Vice President of Fossil Generation of SCS since 1997. Previously served as Plant Manager of Plant Bowen at GEORGIA from March 1993 to August 1997. Warren E. Tate Vice President, Secretary/Treasurer and Regional Chief Information Officer Age 59 Elected in 2000. Served as Vice President since 2001, also serves as Secretary/Treasurer and Regional Chief Information Officer since 1996. The officers of GULF were elected for a term running from the last annual meeting of the directors (July 27, 2001) for one year until the next annual meeting or until their successors are elected and have qualified. I-31 EXECUTIVE OFFICERS OF MISSISSIPPI (Identification of executive officers of MISSISSIPPI is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2001. Michael D. Garrett President, Chief Executive Officer and Director Age 52 Elected in 2001. Previously served as Executive Vice President - Customer Service of ALABAMA from January 2000 to May 2001; Executive Vice President of External Affairs of ALABAMA from March 1998 to January 2000; and Senior Vice President of External Affairs of ALABAMA from February 1994 to March 1998. H. E. Blakeslee Vice President Age 61 Elected in 1984. Served as Vice President of Customer Services and Retail Marketing since 1984. Don E. Mason Vice President Age 60 Elected in 1983. Served as Vice President of External Affairs and Corporate Services since 1983. Michael W. Southern Vice President, Treasurer and Chief Financial Officer Age 49 Elected in 1995. Served as Vice President, Treasurer and Chief Financial Officer since 2001. Previously served as Vice President, Secretary, Treasurer and Chief Financial Officer from 1995 to 2001. Gene L. Ussery, Jr. Vice President Age 52 Elected in 2000. Served as Vice President of Power Generation and Delivery since September 2000. Previously served as Northern Cluster Manager at GEORGIA for Plants Hammond, Bowen and McDonough-Atkinson from July 2000 to September 2000. He served as Manager of Plant Bowen at GEORGIA from 1997 to 2000; and Manager of Plant McDonough at GEORGIA from 1996 to 1997. The officers of MISSISSIPPI were elected for a term running from the last annual meeting of the directors (April 25, 2001) for one year until the next annual meeting or until their successors are elected and have qualified. I-32 PART II Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS (a) The common stock of SOUTHERN is listed and traded on the New York Stock Exchange. The stock is also traded on regional exchanges across the United States. High and low stock prices, per the New York Stock Exchange Composite Tape during each quarter for the past two years were as follows: ------------------------ ------------ -- -------------- High Low ------------ -------------- 2001 First Quarter (Note) $21.650 $16.152 Second Quarter 23.880 20.890 Third Quarter 26.000 22.050 Fourth Quarter 25.980 22.300 2000 First Quarter $25.875 $20.375 Second Quarter 27.875 21.688 Third Quarter 35.000 23.406 Fourth Quarter 33.880 27.500 ---------------------- -------------- -- -------------- Note: The common stock high and low prices have been adjusted to give effect to the Mirant spin off. Reference is made to Note 11 to the financial statements for SOUTHERN in Item 8 herein for additional information. There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 28, 2002, the closing price of SOUTHERN's common stock was $25.40. (b) Number of SOUTHERN's common stockholders of record at December 31, 2001: 150,242 Each of the other registrants have one common stockholder, SOUTHERN. (c) Dividends on each registrant's common stock are payable at the discretion of their respective board of directors. The dividends on common stock declared by SOUTHERN and the operating companies to their stockholder(s) for the past two years were as follows: (in thousands) ------------------- --------- ------------- ---------- Registrant Quarter 2001 2000 ------------------- --------- ------------- ---------- SOUTHERN First $228,320 $220,557 Second 229,611 217,289 Third 231,192 217,289 Fourth 232,935 218,098 ALABAMA First 101,200 103,600 Second 97,600 105,200 Third 97,600 104,400 Fourth 97,500 103,900 GEORGIA First 134,500 136,500 Second 130,900 138,600 Third 130,900 137,600 Fourth 131,000 136,900 GULF First 13,500 14,600 Second 13,300 14,900 Third 13,300 14,800 Fourth 13,175 14,700 MISSISSIPPI First 12,800 13,600 Second 12,500 13,800 Third 12,500 13,700 Fourth 12,400 13,600 SAVANNAH First 5,500 6,100 Second 5,400 6,200 Third 5,400 6,000 Fourth 5,400 6,000 ------------------- --------- ------------- ---------- The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of 2000 and 2001. The dividend paid on SOUTHERN's common stock for the first quarter of 2002 was 33.5(cent) per share. The amount of dividends on their common stock that may be paid by the subsidiary registrants (except GEORGIA effective February 27, 2002) is restricted in accordance with their respective first mortgage bond indenture. The amounts of earnings retained in the II-1 business and the amounts restricted against the payment of cash dividends on common stock at December 31, 2001 were as follows: -------------------- ------------------ --- -------------- Retained Restricted Earnings Amount ------------------ -------------- (in millions) ALABAMA $1,220 $ 796 GEORGIA 1,871 1,037 GULF 161 127 MISSISSIPPI 186 118 SAVANNAH 110 68 Consolidated 4,517 2,145 -------------------- ------------------ --- -------------- Item 6. SELECTED FINANCIAL DATA SOUTHERN. Reference is made to information under the heading "Selected Consolidated Financial and Operating Data," contained herein at pages II-43 and II-44. ALABAMA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-78 and II-79. GEORGIA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-114 and II-115. GULF. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-145 and II-146. MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-178 and II-179. SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-207 and II-208. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SOUTHERN. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-8 through II-18. ALABAMA. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-48 through II-57. GEORGIA. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-83 through II-92. GULF. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-119 through II-128. MISSISSIPPI. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-150 through II-159. SAVANNAH. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-183 through II-191. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Reference is made to information in SOUTHERN's "Management's Discussion and Analysis - Market Price Risk" and to Note 1 to SOUTHERN's financial statements under the heading "Financial Instruments" contained herein on pages II-14 and II-29 through II-30, respectively. Reference is also made to "Management's Discussion and Analysis - Exposure to Market Risks" in Item 7 of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH contained herein at pages II-53, II-87 through II-88, II-124, II-155 and II-187, respectively. II-2
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO 2001 FINANCIAL STATEMENTS Page The Southern Company and Subsidiary Companies: Report of Independent Public Accountants................................................................................ II-7 Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999.................................. II-19 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999.............................. II-20 Consolidated Balance Sheets at December 31, 2001 and 2000............................................................... II-21 Consolidated Statements of Capitalization at December 31, 2001 and 2000................................................. II-23 Consolidated Statements of Common Stockholders' Equity for the Years Ended December 31, 2001, 2000 and 1999..................................................................................... II-25 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999..................................................................................... II-25 Notes to Financial Statements........................................................................................... II-26 ALABAMA: Report of Independent Public Accountants .............................................................................. II-47 Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-58 Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-59 Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-60 Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-62 Statements of Common Stockholder's Equity for the Years Ended December 31, 2001, 2000 and 1999.................................................................................... II-64 Notes to Financial Statements........................................................................................... II-65 GEORGIA: Report of Independent Public Accountants................................................................................ II-82 Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-93 Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-94 Balance Sheets at December 31, 2001 and 2000............................................................................ II-95 Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-97 Statements of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999.................................................................................... II-99 Statements of Common Stockholder's Equity for the Years Ended December 31, 2001, 2000 and 1999.................................................................................... II-99 Notes to Financial Statements........................................................................................... II-100 GULF: Report of Independent Public Accountants................................................................................ II-118 Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-129 Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-130 Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-131 Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-133 Statements of Common Stockholder's Equity for the Years Ended December 31, 2001, 2000 and 1999.................................................................................... II-134 Notes to Financial Statements........................................................................................... II-135 II-3 Page MISSISSIPPI: Report of Independent Public Accountants................................................................................ II-149 Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-160 Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-161 Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-162 Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-164 Statements of Common Stockholder's Equity for the Years Ended December 31, 2001, 2000 and 1999.................................................................................... II-166 Notes to Financial Statements........................................................................................... II-167 SAVANNAH: Report of Independent Public Accountants................................................................................ II-182 Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-192 Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-193 Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-194 Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-196 Statements of Common Stockholder's Equity for the Years Ended December 31, 2001, 2000 and 1999.................................................................................... II-197 Notes to Financial Statements........................................................................................... II-198
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. II-4 SOUTHERN COMPANY FINANCIAL SECTION II-5 MANAGEMENT'S REPORT Southern Company and Subsidiary Companies 2001 Annual Report The management of Southern Company has prepared -- and is responsible for -- the consolidated financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements. The company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship. The company's system of internal accounting controls is evaluated on an ongoing basis by the company's internal audit staff. The company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. The audit committee of the board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time. Management believes that its policies and procedures provide reasonable assurance that the company's operations are conducted according to a high standard of business ethics. In management's opinion, the consolidated financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Southern Company and its subsidiary companies in conformity with accounting principles generally accepted in the United States. /s/H. Allen Franklin H. Allen Franklin Chairman, President, and Chief Executive Officer /s/Gale E. Klappa Gale E. Klappa Executive Vice President, Chief Financial Officer, and Treasurer February 13, 2002 II-6 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Southern Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company (a Delaware corporation) and subsidiary companies as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements (pages II-19 through II-42) referred to above present fairly, in all material respects, the financial position of Southern Company and subsidiary companies as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2001, Southern Company changed its method of accounting for derivative instruments and hedging activities. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 II-7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 2001 Annual Report RESULTS OF OPERATIONS --------------------- OVERVIEW OF CONSOLIDATED EARNINGS AND DIVIDENDS Earnings Southern Company's basic earnings per share from continuing operations increased 6.6 percent in 2001. This increase was achieved by cost containment and lower interest rates despite the mild temperatures and the economic downturn. Basic earnings per share from continuing operations were $1.62 in 2001 compared with $1.52 in 2000. Dilution -- which factors in additional shares related to stock options -- decreased earnings per share by 1 cent in 2001 and had no impact in 2000. In April 2000, Southern Company announced an initial public offering of up to 19.9 percent of Mirant Corporation -- formerly Southern Energy, Inc. -- and intentions to spin off its remaining ownership of 272 million Mirant shares. On April 2, 2001, the tax-free distribution of Mirant shares was completed at a ratio of approximately 0.4 for every share of Southern Company common stock. As a result of the spin off, Southern Company's financial statements and related information reflect Mirant as discontinued operations. Therefore, the focus of Management's Discussion and Analysis is on Southern Company's continuing operations. The following chart shows earnings from continuing and discontinued operations: Consolidated Basic Earnings Net Income Per Share -------------- ----------------- 2001 2000 2001 2000 -------------- ----------------- (in millions) Earnings from -- Continuing operations $1,120 $ 994 $1.62 $1.52 Discontinued operations 142 319 0.21 0.49 ---------------------------------------------------------------- Total earnings $1,262 $1,313 $1.83 $2.01 ================================================================ Dividends Southern Company has paid dividends on its common stock since 1948. Dividends paid on common stock in 2001 and 2000 were $1.34 per share or 331/2 cents per quarter. In January 2002, Southern Company declared a quarterly dividend of 331/2 cents per share. This is the 217th consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. Our dividend payout ratio goal is 75 percent. SOUTHERN COMPANY BUSINESS ACTIVITIES Discussion of the results of continuing operations is focused on Southern Company's primary business of electricity sales by the operating companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- and Southern Power. Southern Power is a new electric wholesale generation subsidiary with market-based rates. The remaining portion of Southern Company's other business activities include telecommunications, energy products and services, leveraged leasing activities, and as the parent holding company. The net impact of these other business activities on the consolidated results of operations is not significant. See Note 12 to the financial statements for additional information. Electricity Business Southern Company's electric utilities generate and sell electricity to retail and wholesale customers in the Southeast. A condensed income statement for these six companies is as follows: Increase (Decrease) Amount From Prior Year ------- ---------------------- 2001 2001 2000 ----------------------------------------------------------------- (in millions) Operating revenues $9,906 $ 46 $735 ----------------------------------------------------------------- Fuel 2,577 13 236 Purchased power 718 41 268 Other operation and maintenance 2,489 19 40 Depreciation and amortization 1,144 9 89 Taxes other than income taxes 533 1 11 ----------------------------------------------------------------- Total operating expenses 7,461 83 644 ----------------------------------------------------------------- Operating income 2,445 (37) 91 Other income, net 15 51 2 ----------------------------------------------------------------- Earnings before interest and taxes 2,460 14 93 Interest expenses and other, net 609 (25) 29 Income taxes 702 (1) 28 ----------------------------------------------------------------- Net income $1,149 $ 40 $ 36 ================================================================= II-8 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report Revenues Operating revenues for the core business of selling electricity in 2001 and the amount of change from the prior year are as follows: Increase (Decrease) Amount From Prior Year ------ ---------------------- 2001 2001 2000 ---------------------------------------------------------------- (in millions) Retail -- Base revenues $5,921 $ (93) $174 Fuel cost recovery and other 2,519 (67) 336 ---------------------------------------------------------------- Total retail 8,440 (160) 510 ---------------------------------------------------------------- Sales for resale -- Within service area 338 (39) 27 Outside service area 836 236 127 ---------------------------------------------------------------- Total sales for resale 1,174 197 154 Other operating revenues 292 9 71 ---------------------------------------------------------------- Operating revenues $9,906 $ 46 $735 ================================================================ Percent change 0.5% 8.1% ---------------------------------------------------------------- Base revenues declined by $93 million in 2001 because of mild temperatures and the economic downturn. Total base revenues of $6.0 billion in 2000 increased as a result of continued customer growth in the service area and the positive impact of weather on energy sales. Electric rates -- for the operating companies -- include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses -- including the fuel component of purchased energy -- and do not affect net income. However, cash flow is affected by the economic loss from untimely recovery of these receivables. Sales for resale revenues within the service area were $338 million in 2001, down 10.2 percent from the prior year. This sharp decline resulted primarily from the mild weather experienced in the Southeast during 2001, which significantly reduced energy requirements from these customers. Sales for resale within the service area for 2000 were up from the prior year as a result of additional demand for electricity during the hot summer. Revenues from energy sales for resale outside the service area have increased sharply the past two years with a 39 percent and 27 percent increase in 2001 and 2000, respectively. This growth was primarily driven by new contracts. As Southern Company increases its competitive wholesale generation business, sales for resale outside the service area should reflect steady increases over the near term. Recent wholesale contracts have shorter contract periods, and many are market priced compared with the traditional cost-based contracts entered into in the 1980s. Those long-term cost-based contracts are principally unit power sales to Florida utilities. Revenues from long-term unit power contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components of the unit power contracts were as follows: 2001 2000 1999 -------------------------------------------------------------- (in millions) Capacity $170 $177 $174 Energy 201 178 157 -------------------------------------------------------------- Total $371 $355 $331 ============================================================== Capacity revenues in 2001 and 2000 varied slightly compared with the prior year as a result of adjustments and true-ups related to contractual pricing. No significant declines in the amount of capacity are scheduled until the termination of the contracts in 2010. Energy Sales Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 2001 and the percent change by year were as follows: Amount Percent Change (billions of -------- -------------------------- kilowatt-hours) 2001 2001 2000 1999 ------------------------------ --------------------------- Residential 44.5 (3.6)% 6.5% (0.2)% Commercial 46.9 1.5 6.6 4.0 Industrial 52.9 (6.8) 1.0 1.6 Other 1.0 0.7 2.7 1.6 Total retail 145.3 (3.2) 4.3 1.7 ----- Sales for resale -- Within service area 9.4 (2.0) 1.5 (4.1) Outside service area 21.4 24.4 33.0 (0.4) ------ Total 176.1 (0.5) 6.4 1.2 ============================================================== II-9 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report Although the number of residential customers increased 43,000 in 2001, retail energy sales registered a 3.2 percent decline. This is the first decrease since 1982. Reduced retail sales in 2001 were driven by extremely mild weather and the sluggish economy, which severely impacted industrial sales. In 2000, the rate of growth in total retail energy sales was very strong. Residential energy sales reflected a substantial increase as a result of the hotter-than-normal summer weather and the increase in customers served. Also in 2000, commercial sales continued to reflect the strong economy in the Southeast. Energy sales to retail customers are projected to increase at an average annual rate of 1.8 percent during the period 2002 through 2012. Sales to customers outside the service area under long-term contracts for unit power sales increased 2.7 percent in 2001 and increased 21 percent in 2000. These changes in sales were influenced by weather -- discussed earlier -- and fluctuations in prices for oil and natural gas. These are the primary fuel sources for utilities with which the company has long-term contracts. However, these fluctuations in energy sales under long-term contracts have minimal effects on earnings because the energy is generally sold at variable cost. Expenses In 2001, operating expenses of $7.5 billion increased only $83 million compared with the prior year. The moderate increase reflected flat energy sales and tighter cost containment measures. The costs to produce electricity for the core business in 2001 increased $96 million. However, non-production operation and maintenance declined by $23 million. In 2000, operating expenses of $7.4 billion increased $644 million compared with the prior year. The costs to produce electricity in 2000 increased by $498 million to meet higher energy requirements. Non-production operation and maintenance expenses increased $46 million in 2000. Depreciation and amortization expenses in 2000 increased $89 million, of which $50 million resulted from additional accelerated amortization by Georgia Power. Fuel costs constitute the single largest expense for the six electric utilities. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated -- within the service area -- were as follows: 2001 2000 1999 --------------------------------------------------------------- Total generation (billions of kilowatt-hours) 174 174 165 Sources of generation (percent) -- Coal 72 78 78 Nuclear 16 16 17 Oil and gas 9 4 3 Hydro 3 2 2 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.56 1.51 1.45 --------------------------------------------------------------- In 2001, fuel and purchased power costs of $3.3 billion increased $54 million. Continued efforts to control energy costs combined with additional efficient gas-fired generating units helped to hold the increase in fuel expense to $13 million in 2001. Total fuel and purchased power costs increased $504 million in 2000 as a result of 10.6 billion more kilowatt-hours being sold than in 1999. Demand was met with some 2.5 billion additional kilowatt-hours being purchased and using generation with higher unit fuel cost than in 1999. Total interest charges and other financing costs in 2001 decreased $25 million from amounts reported in the previous year. The decline reflected substantially lower short-term interest rates that offset new financing costs. Total interest charges and other financing costs in 2000 increased $29 million reflecting some additional external financing for new generating units. Effects of Inflation The operating companies are subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on Southern Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through II-10 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report financing facilities with fixed-money obligations such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed. Future Earnings Potential General The results of continuing operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company's future earnings depends on numerous factors. The two major factors are the ability of the operating companies to achieve energy sales growth while containing cost in a more competitive environment and the profitability of the new competitive market-based wholesale generating facilities being added. Future earnings for the electricity business in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new short and long-term contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the service area. The operating companies operate as vertically integrated companies providing electricity to customers within the service area of the southeastern United States. Prices for electricity provided to retail customers are set by state public service commissions under cost-based regulatory principles. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on earned return on equity. See Note 3 to the financial statements for additional information about these and other regulatory matters. In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, Southern Company recorded non-cash income of approximately $124 million in 2001. Future pension income is dependent on several factors including trust earnings and changes to the plan. For the operating companies, pension income is a component of the regulated rates and does not have a significant effect on net income. For more information, see Note 2 to the financial statements. Southern Company currently receives tax benefits related to investments in alternative fuel partnerships and leveraged lease agreements for energy generation, distribution, and transportation assets that contribute significantly to the economic results for these projects. Changes in Internal Revenue Service interpretations of existing regulations or challenges to the company's positions could result in reduced availability or changes in the timing of such tax benefits. The net income impact of these investments totaled $52 million, $28 million, and $11 million in 2001, 2000, and 1999, respectively. See Note 1 to the financial statements under "Leveraged Leases" and Note 6 for additional information and related income taxes. Southern Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings. Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters." Industry Restructuring The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it has been a major catalyst for recent restructuring and consolidations taking place within the utility industry. Numerous federal and state initiatives are in varying stages that promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Alabama, Florida, Georgia, and Mississippi, none have been enacted. Enactment would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California. As a result of that crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. II-11 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if Southern Company's electric utilities do not remain low-cost producers and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings. To adapt to a less regulated, more competitive environment, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, acquisitions involving other utility or non-utility businesses or properties, internal restructuring, disposition of certain assets, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations and financial condition of Southern Company. The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators and foreign utilities to sell power largely free from regulation under PUHCA. These entities are able to own and operate power generating facilities and sell power to affiliates -- under certain restrictions. Southern Company is working to maintain and expand its share of wholesale energy sales in the Southeastern power markets. In January 2001, Southern Company formed a new subsidiary -- Southern Power Company. This subsidiary constructs, owns, and manages wholesale generating assets in the Southeast. Southern Power will be the primary growth engine for Southern Company's competitive wholesale market-based energy business. By the end of 2003, Southern Power plans to have approximately 4,700 megawatts of generating capacity in commercial operation. At December 31, 2001, 800 megawatts are in commercial operation and some 3,900 megawatts of capacity are under construction. In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In January 2002, the sponsors of SeTrans held a public meeting to form a Stakeholder Advisory Committee, which will participate in the development of the RTO. Southern Company continues to work with the other sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to have a material impact on Southern Company's financial statements. The outcome of this matter cannot now be determined. Accounting Policies Critical Policy Southern Company's significant accounting policies are described in Note 1 to the financial statements. The company's most critical accounting policy involves rate regulation. The operating companies are subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of a company's operations is no longer subject to these provisions, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information. New Accounting Standards Effective January 2001, Southern Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Statement No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. See Note 1 to the financial statements under "Financial Instruments" for additional information. The impact on net income in 2001 was not material. An additional interpretation of Statement No. 133 will result in a change -- effective April 1, 2002 -- in accounting for certain contracts related to fuel supplies that contain quantity options. These contracts will be accounted for as derivatives and marked to market. However, due to the existence of specific II-12 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report cost-based fuel recovery clauses for the operating companies, this change is not expected to have a material impact on net income. In June 2001, the FASB issued Statement No. 142, Goodwill and Other Intangible Assets, which establishes new accounting and reporting standards for acquired goodwill and other intangible assets and supersedes Accounting Principles Board Opinion No. 17. Statement No. 142 addresses how intangible assets that are acquired individually or with a group of other assets -- but not those acquired in a business combination -- should be accounted for upon acquisition and on an ongoing basis. Goodwill and intangible assets that have indefinite useful lives will not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives, which are no longer limited to 40 years. Southern Company adopted Statement No. 142 in January 2002 with no material impact on the financial statements. Also in June 2001, the FASB issued Statement No. 143, Asset Retirement Obligations, which establishes new accounting and reporting standards for legal obligations associated with retiring assets, including decommissioning of nuclear plants. The liability for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expenses. Statement No. 143 must be adopted by January 1, 2003. Southern Company has not yet quantified the impact of adopting Statement No. 143 on its financial statements. FINANCIAL CONDITION ------------------ Overview Southern Company's financial condition continues to remain strong. In 2001, most of the operating companies' earnings were at the high end of their respective allowed range of return on equity. Also, earnings from new business activities made a solid contribution. These factors drove consolidated net income from continuing operations to a record $1.12 billion in 2001. The quarterly dividend declared in January 2002 was 331/2 cents per share, or $1.34 on an annual basis. Southern Company is committed to a goal of increasing the dividend over time consistent with growth in earnings. Southern Company's target is to grow earnings per share at an average annual rate of 5 percent or more. The dividend payout ratio goal is 75 percent. Gross property additions to utility plant from continuing operations were $2.6 billion in 2001. The majority of funds needed for gross property additions since 1998 has been provided from operating activities. The Consolidated Statements of Cash Flows provide additional details. Off-Balance Sheet Financing Arrangements At December 31, 2001, Southern Company utilized two separate financing arrangements that are not required to be recorded on the balance sheet. In May 2001, Mississippi Power began the initial 10-year term of an operating lease agreement signed in 1999 with Escatawpa Funding, Limited Partnership, a special purpose entity, to use a combined-cycle generating facility located at Mississippi Power's Plant Daniel. The facility cost approximately $370 million. The lease provides for a residual value guarantee -- approximately 71 percent of the completion cost -- by Mississippi Power that is due upon termination of the lease in certain circumstances. See Note 9 to the financial statements under "Operating Leases" for additional information regarding this lease. Southern Power in 2001 entered into a financial arrangement with Westdeutsche Landesbank Girozentrale (WestLB) that is in effect until September 2002. Under this agreement, Southern Power may assign up to $125 million in vendor contracts for equipment to WestLB. For accounting purposes, WestLB is the owner of the contracts. Southern Power acts as an agent for WestLB and instructs WestLB when to make payments to the vendors. At December 31, 2001, approximately $47 million of such vendor equipment contracts had been assigned to WestLB. Southern Power currently anticipates terminating this arrangement and reacquiring these assets in the first quarter of 2002. Credit Rating Risk Southern Company and its subsidiaries do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral -- but not accelerated payment -- in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity sales, fixed-price physical gas purchases, and agreements covering interest rate swaps and currency swaps. At December 31, 2001, the maximum potential collateral requirements under the electricity sale contracts were approximately $230 million. Generally, collateral may be provided for by a Southern Company guaranty, a letter of credit, or cash. At December 31, 2001, there were no II-13 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report material collateral requirements for the gas purchase contracts or other financial instrument agreements. Market Price Risk Southern Company is exposed to market risks, including changes in interest rates, currency exchange rates, and certain commodity prices. To manage the volatility attributable to these exposures, the company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the company's policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis. The company's market risk exposures relative to interest rate changes have not changed materially compared with the previous reporting period. In addition, the company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. If the company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $22 million at December 31, 2001. Based on the company's overall interest rate exposure at December 31, 2001, including derivative and other interest rate sensitive instruments, a near-term 100 basis point change in interest rates would not materially affect the consolidated financial statements. Due to cost-based rate regulations, the operating companies have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices for the operating companies, they and Southern Power enter into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and to a lesser extent similar contracts for gas purchases. Also, some of the operating companies have implemented fuel-hedging programs at the instruction of their respective public service commissions. Realized gains and losses are recognized in the income statement as incurred. At December 31, 2001, exposure from these activities was not material to the consolidated financial statements. Fair value of changes in energy trading contracts and year-end valuations are as follows: Changes During the Year --------------------------------------------------------------- Fair Value --------------------------------------------------------------- (in millions) Contracts beginning of year $ 1.7 Contracts realized or settled (1.4) New contracts - Changes in valuation techniques - Current period changes 1.0 -------------------------------------------------------------- Contracts end of year $ 1.3 ============================================================== Source of Year-End Valuation Prices -------------------------------------------------------------- Maturity Total ------------------- Fair Value Year 1 1-3 Years -------------------------------------------------------------- (in millions) Actively quoted $(3.8) $(5.1) $1.3 External sources 5.1 5.1 - Models and other methods - - - -------------------------------------------------------------- Contracts end of year $ 1.3 $ - $1.3 ============================================================== For additional information, see Note 1 to the financial statements under "Financial Instruments." Capital Structure During 2001, the operating companies issued $1.2 billion of senior notes. The majority of these proceeds was used to retire long-term debt. The companies continued to reduce financing costs by retiring higher-cost securities. Retirements of bonds and senior notes, including maturities, totaled $1.2 billion in 2001, $298 million during 2000, and $1.2 billion during 1999. Southern Company issued through the company's stock plans 17 million treasury shares of common stock in 2001. Proceeds were $395 million and were primarily used to reduce short-term debt. At December 31, 2001, approximately 2 million treasury shares remain unissued. At the close of 2001, the company's common stock market value was $25.35 per share, compared with book value of $11.44 per share. The market-to-book value ratio was 222 percent at the end of 2001, compared with 212 percent at year-end 2000. II-14 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report Capital Requirements for Construction The construction program of Southern Company is budgeted at $2.8 billion for 2002, $2.1 billion for 2003, and $2.3 billion for 2004. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Southern Company has approximately 4,500 megawatts of new generating capacity scheduled to be placed in service by 2003. Approximately 3,900 megawatts of additional new capacity will be dedicated to the wholesale market and owned by Southern Power. Significant construction of transmission and distribution facilities and upgrading of generating plants will be continuing. Other Capital Requirements In addition to the funds needed for the construction program, approximately $2.4 billion will be required by the end of 2004 for present improvement fund requirements and maturities of long-term debt. Also, the subsidiaries will continue to retire higher-cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit. These capital requirements, lease obligations, and purchase commitments -- discussed in Notes 8 and 9 to the financial statements -- are as follows: 2002 2003 2004 -------------------------------------------------------------- (in millions) Bonds - First mortgage $ 7 $ - $ - Pollution control 8 - - Notes 410 1,072 890 Leases - Capital 4 4 4 Operating 74 71 70 Purchase commitments - Fuel 2,399 2,185 1,541 Purchased power 97 100 95 -------------------------------------------------------------- At the beginning of 2002, Southern Company had used $293 million of its available credit arrangements. Credit arrangements are as follows: Expires ---------------------------- Total Unused 2002 2003 & Beyond -------------------------------------------------------------- (in millions) $5,423 $5,130 $3,658 $1,472 -------------------------------------------------------------- Environmental Matters On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court in Georgia against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning- plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add Gulf Power and Mississippi Power based on lack of jurisdiction over those companies. The court directed the EPA to refile its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. The EPA refiled those claims as directed by the court. Also, the EPA refiled its claims against Alabama Power in U.S. II-15 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report District Court in Alabama. It has not refiled against Gulf Power, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case could have a significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and Savannah Electric have opposed that motion. Southern Company believes that its operating companies complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Southern Company. Reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995. Southern Company achieved Phase I compliance at its affected plants by primarily switching to low-sulfur coal and with some equipment upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $300 million. Phase II sulfur dioxide compliance was required in 2000. Southern Company used emission allowances and fuel switching to comply with Phase II requirements. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment requirements increased total construction expenditures through 2000 by approximately $100 million. Respective state plans to address the one-hour ozone non-attainment standards for the Atlanta and Birmingham areas have been established and must be implemented in May 2003. Seven generating plants in the Atlanta area and two plants in the Birmingham area will be affected. Construction expenditures for compliance with these new rules are currently estimated at approximately $940 million, of which $520 million remains to be spent. A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered. In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals is considering other legal challenges to these standards. A court decision is expected in the spring of 2002. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued regional nitrogen oxide reduction rules to the states for implementation. The final rule affects 21 states, including Alabama and Georgia. Compliance is required by May 31, 2004, for most states, including Alabama. For Georgia, further rulemaking was required, and proposed compliance was delayed until May 1, 2005. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $190 million. In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act, and the regulations are scheduled to be finalized by the end of 2004 with implementation to take place around 2007. In January 2001, the EPA II-16 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report proposed guidance for the determination of Best Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls is expected to take place around 2010. Litigation of the Regional Haze Regulations, including the BART provisions, is ongoing in the Federal District of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002. Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide and reductions in mercury and other HAPS emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. In October 1997, the EPA issued regulations setting forth requirements for Compliance Assurance Monitoring in its state and federal operating permit programs. These regulations were amended by the EPA in March 2001 in response to a court order resolving challenges to the rules brought by environmental groups and the utility industry. Generally, this rule affects the operation and maintenance of electrostatic precipitators and could involve significant additional ongoing expense. The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the subsidiaries could incur substantial costs to clean up properties. The subsidiaries conduct studies to determine the extent of any required cleanup and have recognized in their respective financial statements costs to clean up known sites. These costs for Southern Company amounted to $1 million in 2001 and $4 million in both 2000 and 1999. Additional sites may require environmental remediation for which the subsidiaries may be liable for a portion or all required cleanup costs. See Note 3 to the financial statements for information regarding Georgia Power's potentially responsible party status at sites in Georgia. Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of Southern Company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect Southern Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields. Sources of Capital The amount and timing of additional equity capital to be raised in 2002 -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. Equity capital can be provided from any combination of public offerings, private placements, or the company's stock plans. The operating companies plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from internal sources. However, the type and timing of any financings -- if needed -- will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt and trust preferred securities. Southern Power will use both external funds and equity capital from Southern Company to finance its construction program. To meet short-term cash needs and contingencies, Southern Company had at the beginning of 2002 approximately $354 million of cash and cash equivalents and $5.1 billion of unused credit arrangements with banks. II-17 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2001 Annual Report Cautionary Statement Regarding Forward-Looking Information Southern Company's 2001 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the strategic goals for Southern Company's new wholesale business and also Southern Company's goals for dividend payout ratio, earnings per share, and earnings growth. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other comparable terminology. Southern Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations; current and future litigation, including the pending EPA civil action against certain Southern Company subsidiaries and the race discrimination litigation against certain Southern Company subsidiaries; the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; the performance of projects undertaken by the non-traditional business and the success of efforts to invest in and develop new opportunities; 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 Southern Company or its subsidiaries; the effects of, and changes in, economic conditions in the areas in which Southern Company's subsidiaries operate; the direct or indirect effects on Southern Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and acceptance of Southern Company's new product and service offerings; the ability of Southern Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by Southern Company with the Securities and Exchange Commission. 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CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2001, 2000, and 1999 Southern Company and Subsidiary Companies 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------ (in millions) Operating Revenues: Retail sales $ 8,440 $ 8,600 $8,090 Sales for resale 1,174 977 823 Other revenues 541 489 404 ------------------------------------------------------------------------------------------------------------------------------ Total operating revenues 10,155 10,066 9,317 ------------------------------------------------------------------------------------------------------------------------------ Operating Expenses: Fuel 2,577 2,564 2,328 Purchased power 718 677 409 Other operations 1,852 1,861 1,838 Maintenance 909 852 829 Depreciation and amortization 1,173 1,171 1,139 Taxes other than income taxes 535 536 523 ------------------------------------------------------------------------------------------------------------------------------ Total operating expenses 7,764 7,661 7,066 ------------------------------------------------------------------------------------------------------------------------------ Operating Income 2,391 2,405 2,251 Other Income: Interest income 27 29 30 Other, net 3 (21) (45) ------------------------------------------------------------------------------------------------------------------------------ Earnings From Continuing Operations Before Interest and Income Taxes 2,421 2,413 2,236 ------------------------------------------------------------------------------------------------------------------------------ Interest and Other: Interest expense, net 557 643 527 Distributions on capital and preferred securities of subsidiaries 169 169 175 Preferred dividends of subsidiaries 18 19 20 ------------------------------------------------------------------------------------------------------------------------------ Total interest and other 744 831 722 ------------------------------------------------------------------------------------------------------------------------------ Earnings From Continuing Operations Before Income Taxes 1,677 1,582 1,514 Income taxes 558 588 599 ------------------------------------------------------------------------------------------------------------------------------ Earnings From Continuing Operations Before Cumulative Effect of Accounting Change 1,119 994 915 Cumulative effect of accounting change -- less income taxes of less than $1 1 - - ------------------------------------------------------------------------------------------------------------------------------ Earnings From Continuing Operations 1,120 994 915 Earnings from discontinued operations, net of income taxes of $93, $86, and $127 for 2001, 2000, and 1999, respectively 142 319 361 ------------------------------------------------------------------------------------------------------------------------------ Consolidated Net Income $ 1,262 $ 1,313 $1,276 ============================================================================================================================== Common Stock Data: Earnings per share from continuing operations - Basic $1.62 $1.52 $1.33 Diluted 1.61 1.52 1.33 Earnings per share including discontinued operations - Basic $1.83 $2.01 $1.86 Diluted 1.82 2.01 1.86 ------------------------------------------------------------------------------------------------------------------------------ Average number of shares of common stock outstanding - (in millions) Basic 689 653 685 Diluted 694 654 686 ------------------------------------------------------------------------------------------------------------------------------ Cash dividends paid per share of common stock $1.34 $1.34 $1.34 ------------------------------------------------------------------------------------------------------------------------------ The accompanying notes are an integral part of these statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001, 2000, and 1999 Southern Company and Subsidiary Companies 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------ (in millions) Operating Activities: Consolidated net income $ 1,262 $ 1,313 $ 1,276 Adjustments to reconcile consolidated net income to net cash provided from operating activities -- Less income from discontinued operations 142 319 361 Depreciation and amortization 1,358 1,337 1,216 Deferred income taxes and investment tax credits (22) 97 10 Other, net (192) 18 118 Changes in certain current assets and liabilities -- Receivables, net 344 (379) (141) Fossil fuel stock (199) 78 (41) Materials and supplies (43) (15) (37) Accounts payable (51) 180 (65) Other 69 66 244 ------------------------------------------------------------------------------------------------------------------------------ Net cash provided from operating activities of continuing operations 2,384 2,376 2,219 ------------------------------------------------------------------------------------------------------------------------------ Investing Activities: Gross property additions (2,617) (2,225) (1,881) Other (119) (81) (362) ------------------------------------------------------------------------------------------------------------------------------ Net cash used for investing activities of continuing operations (2,736) (2,306) (2,243) ------------------------------------------------------------------------------------------------------------------------------ Financing Activities: Increase (decrease) in notes payable, net 223 (275) 831 Proceeds -- Long-term senior notes 1,242 650 840 Other long-term debt 757 93 629 Capital and preferred securities 30 - 250 Common stock 395 910 24 Redemptions -- First mortgage bonds (616) (211) (890) Other long-term debt (569) (204) (483) Capital and preferred securities - - (100) Preferred stock - - (86) Common stock repurchased - (415) (862) Payment of common stock dividends (922) (873) (921) Other (33) (54) (50) ------------------------------------------------------------------------------------------------------------------------------ Net cash provided from (used for) financing activities of continuing operations 507 (379) (818) ------------------------------------------------------------------------------------------------------------------------------ Cash provided from (used for) discontinued operations - 354 684 ------------------------------------------------------------------------------------------------------------------------------ Net Increase (Decrease) in Cash and Cash Equivalents 155 45 (158) Cash and Cash Equivalents at Beginning of Year 199 154 312 ------------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at End of Year $ 354 $ 199 $ 154 ============================================================================================================================== Supplemental Cash Flow Information From Continuing Operations: Cash paid during the year for -- Interest (net of amount capitalized) $624 $802 $684 Income taxes $721 $666 $656 ------------------------------------------------------------------------------------------------------------------------------ The accompanying notes are an integral part of these statements.
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CONSOLIDATED BALANCE SHEETS At December 31, 2001 and 2000 Southern Company and Subsidiary Companies 2001 Annual Report ------------------------------------------------------------------------------------------------------------------- Assets 2001 2000 ------------------------------------------------------------------------------------------------------------------- (in millions) Current Assets: Cash and cash equivalents $ 354 $ 199 Special deposits 23 6 Receivables, less accumulated provisions for uncollectible accounts of $24 in 2001 and $22 in 2000 1,132 1,312 Under recovered retail fuel clause revenue 280 418 Fossil fuel stock, at average cost 394 195 Materials and supplies, at average cost 550 507 Other 223 188 ------------------------------------------------------------------------------------------------------------------- Total current assets 2,956 2,825 ------------------------------------------------------------------------------------------------------------------- Property, Plant, and Equipment: In service 35,813 34,188 Less accumulated depreciation 15,020 14,350 ------------------------------------------------------------------------------------------------------------------- 20,793 19,838 Nuclear fuel, at amortized cost 202 215 Construction work in progress 2,089 1,569 ------------------------------------------------------------------------------------------------------------------- Total property, plant, and equipment 23,084 21,622 ------------------------------------------------------------------------------------------------------------------- Other Property and Investments: Nuclear decommissioning trusts, at fair value 682 690 Net assets of discontinued operations - 3,320 Leveraged leases 655 596 Other 193 161 ------------------------------------------------------------------------------------------------------------------- Total other property and investments 1,530 4,767 ------------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets: Deferred charges related to income taxes 924 957 Prepaid pension costs 547 398 Debt expense, being amortized 103 99 Premium on reacquired debt, being amortized 280 280 Other 400 312 ------------------------------------------------------------------------------------------------------------------- Total deferred charges and other assets 2,254 2,046 ------------------------------------------------------------------------------------------------------------------- Total Assets $29,824 $31,260 =================================================================================================================== The accompanying notes are an integral part of these balance sheets.
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CONSOLIDATED BALANCE SHEETS (continued) At December 31, 2001 and 2000 Southern Company and Subsidiary Companies 2001 Annual Report ----------------------------------------------------------------------------------------------------------------- Liabilities and Stockholders' Equity 2001 2000 ----------------------------------------------------------------------------------------------------------------- (in millions) Current Liabilities: Securities due within one year $ 429 $ 67 Notes payable 1,902 1,680 Accounts payable 847 869 Customer deposits 153 140 Taxes accrued -- Income taxes 160 88 Other 193 208 Interest accrued 118 121 Vacation pay accrued 125 119 Other 445 426 ----------------------------------------------------------------------------------------------------------------- Total current liabilities 4,372 3,718 ----------------------------------------------------------------------------------------------------------------- Long-term debt (See accompanying statements) 8,297 7,843 ----------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 4,088 4,074 Deferred credits related to income taxes 500 551 Accumulated deferred investment tax credits 634 664 Employee benefits provisions 450 401 Prepaid capacity revenues 41 58 Other 814 647 ---------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 6,527 6,395 ---------------------------------------------------------------------------------------------------------------- Company or subsidiary obligated mandatorily redeemable capital and preferred securities (See accompanying statements) 2,276 2,246 ---------------------------------------------------------------------------------------------------------------- Cumulative preferred stock of subsidiaries (See accompanying statements) 368 368 ---------------------------------------------------------------------------------------------------------------- Common stockholders' equity (See accompanying statements) 7,984 10,690 ---------------------------------------------------------------------------------------------------------------- Total Liabilities and Stockholders' Equity $29,824 $31,260 ================================================================================================================ Commitments and Contingent Matters (Notes 1, 2, 3, 5, 8, 9, and 10) ---------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of these balance sheets.
II-22
CONSOLIDATED SATEEMENTS OF CAPITALIZATION At December 31, 2001 and 2000 Southern Company and Subsidiary Companies 2001 Annual Report ---------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ---------------------------------------------------------------------------------------------------------------------------- (in millions) (percent of total) Long-Term Debt of Subsidiaries: First mortgage bonds -- Maturity Interest Rates -------- -------------- 2003 6.13% to 6.63% $ - $ 325 2004 6.60% - 35 2005 6.07% 2 10 2006 6.50% to 6.90% 45 45 2007 through 2011 6.88% - 50 2021 through 2025 6.88% to 9.00% 437 635 2026 through 2030 6.88% 30 30 ---------------------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 514 1,130 ---------------------------------------------------------------------------------------------------------------------------- Long-term senior notes payable -- 4.69% to 9.75% due 2002-2005 1,834 766 5.38% to 8.58% due 2006-2009 595 744 6.10% to 7.63% due 2010-2017 305 170 6.38% to 8.12% due 2018-2038 788 793 6.63% to 7.13% due 2039-2048 1,029 1,029 Adjustable rates (1.98% to 3.44% at 1/1/02) due 2002-2005 1,078 734 ---------------------------------------------------------------------------------------------------------------------------- Total long-term senior notes payable 5,629 4,236 ---------------------------------------------------------------------------------------------------------------------------- Other long-term debt -- Pollution control revenue bonds -- Collateralized: 5.00% to 6.75% due 2005-2026 168 539 Variable rates (1.61% to 1.95% at 1/1/02) due 2015-2025 90 90 Non-collateralized: 4.20% to 6.75% due 2015-2034 726 406 Variable rates (1.75% to 2.05% at 1/1/02) due 2011-2037 1,566 1,475 ---------------------------------------------------------------------------------------------------------------------------- Total other long-term debt 2,550 2,510 ---------------------------------------------------------------------------------------------------------------------------- Capitalized lease obligations 92 95 ---------------------------------------------------------------------------------------------------------------------------- Unamortized debt (discount), net (59) (61) ---------------------------------------------------------------------------------------------------------------------------- Total long-term debt (annual interest requirement -- $443 million) 8,726 7,910 Less amount due within one year 429 67 ---------------------------------------------------------------------------------------------------------------------------- Long-term debt excluding amount due within one year 8,297 7,843 43.9% 37.1% ----------------------------------------------------------------------------------------------------------------------------
II-23
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2001 and 2000 Southern Company and Subsidiary Companies 2001 Annual Report --------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 --------------------------------------------------------------------------------------------------------------------------- (in millions) (percent of total) Company or Subsidiary Obligated Mandatorily Redeemable Capital and Preferred Securities: $25 liquidation value -- 6.85% to 7.00% 435 435 7.13% to 7.38% 327 297 7.60% to 7.63% 415 415 7.75% 649 649 8.14% to 8.19% 400 400 Auction rate (3.60% at 1/1/02) 50 50 --------------------------------------------------------------------------------------------------------------------------- Total company or subsidiary obligated mandatorily redeemable capital and preferred securities (annual distribution requirement -- $170 million) 2,276 2,246 12.0 10.6 --------------------------------------------------------------------------------------------------------------------------- Cumulative Preferred Stock of Subsidiaries: $100 par or stated value -- 4.20% to 7.00% 98 98 $25 par or stated value -- 5.20% to 5.83% 200 200 Adjustable and auction rates -- at 1/1/02: 3.10% to 3.56% 70 70 --------------------------------------------------------------------------------------------------------------------------- Total cumulative preferred stock of subsidiaries (annual dividend requirement -- $18 million) 368 368 1.9 1.7 --------------------------------------------------------------------------------------------------------------------------- Common Stockholders' Equity: Common stock, par value $5 per share -- Authorized -- 1 billion shares Issued -- 2001: 701 million shares -- 2000: 701 million shares Treasury -- 2001: 2 million shares -- 2000: 19 million shares Par value 3,503 3,503 Paid-in capital 14 3,153 Treasury, at cost (57) (545) Retained earnings 4,517 4,672 Accumulated other comprehensive income -- From continuing operations 7 - From discontinued operations - (93) --------------------------------------------------------------------------------------------------------------------------- Total common stockholders' equity 7,984 10,690 42.2 50.6 --------------------------------------------------------------------------------------------------------------------------- Total Capitalization $18,925 $21,147 100.0% 100.0% =========================================================================================================================== The accompanying notes are an integral part of these statements.
II-24
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY For the Years Ended December 31, 2001, 2000, and 1999 Southern Company and Subsidiary Companies 2001 Annual Report Accumulated Other Comprehensive Common Stock Income From -------------------------- ----------------------------- Par Paid-In Retained Continuing Discontinued Value Capital Treasury Earnings Operations Operations Total ------------------------------------------------------------------------------------------------------------------------------- (in millions) Balance at December 31, 1998 $3,499 $2,463 $ (58) $3,878 $ - $ 15 $ 9,797 Net income - - - 1,276 - - 1,276 Other comprehensive income - - - - - (107) (107) Stock issued 4 17 1 - - - 22 Stock repurchased, at cost - - (861) - - - (861) Cash dividends - - - (921) - - (921) Other - - (1) (1) - - (2) ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 3,503 2,480 (919) 4,232 - (92) 9,204 Net income - - - 1,313 - - 1,313 Other comprehensive income - - - - - (1) (1) Stock issued - 121 789 - - - 910 Stock repurchased, at cost - - (414) - - - (414) Cash dividends - - - (873) - - (873) Other - 552 (1) - - - 551 ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 3,503 3,153 (545) 4,672 - (93) 10,690 Net income - - - 1,262 - - 1,262 Other comprehensive income - - - - 7 93 100 Stock issued - - 488 (93) - - 395 Mirant spin off distribution - (3,168) - (391) - - (3,559) Cash dividends - - - (922) - - (922) Other - 29 - (11) - - 18 ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 $3,503 $ 14 $ (57) $4,517 $ 7 $ - $ 7,984 ===============================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2001, 2000, and 1999 Southern Company and Subsidiary Companies 2001 Annual Report -------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 -------------------------------------------------------------------------------------------------------------------------- (in millions) Consolidated Net Income $1,262 $1,313 $1,276 -------------------------------------------------------------------------------------------------------------------------- Other comprehensive income -- continuing operations: Changes in fair value of qualifying cash flow hedges, net of tax of $4 7 - - -------------------------------------------------------------------------------------------------------------------------- Total other comprehensive income -- continuing operations 7 - - -------------------------------------------------------------------------------------------------------------------------- Other comprehensive income -- discontinued operations: Cumulative effect of accounting change for qualifying hedges, net of tax of $(121) (249) - - Changes in fair value of qualifying hedges, net of tax of $(51) (104) - - Less: Reclassification adjustment for amounts included in net income, net of tax of $29 60 - - Foreign currency translation adjustments, net of tax of $(22), $(1), and $(58) for the years 2001, 2000, and 1999, respectively (22) (1) (107) -------------------------------------------------------------------------------------------------------------------------- Total other comprehensive income -- discontinued operations (315) (1) (107) -------------------------------------------------------------------------------------------------------------------------- Consolidated Comprehensive Income $ 954 $1,312 $1,169 ========================================================================================================================== The accompanying notes are an integral part of these statements.
II-25 NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 2001 Annual Report 1. Summary of Significant Accounting Policies General Southern Company is the parent company of five operating companies, a system service company, Southern Communications Services (Southern LINC), Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern Power), and other direct and indirect subsidiaries. The operating companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four Southeastern states. Contracts among the operating companies -- related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. On April 2, 2001, the spin off of Mirant Corporation (Mirant) was completed. As a result of the spin off, Southern Company's financial statements and related information reflect Mirant as discontinued operations. For additional information, see Note 11. The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. All material intercompany items have been eliminated in consolidation. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform with the current year presentation. Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The operating companies also are subject to regulation by the FERC and their respective state public service commissions. The companies follow accounting principles generally accepted in the United States and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires the use of estimates, and the actual results may differ from those estimates. Regulatory Assets and Liabilities The operating companies are subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Consolidated Balance Sheets at December 31 relate to the following: 2001 2000 --------------------------------------------------------------- (in millions) Deferred income tax charges $ 924 $ 957 Premium on reacquired debt 280 280 Department of Energy assessments 39 46 Vacation pay 95 92 Postretirement benefits 28 30 Deferred income tax credits (500) (551) Accelerated amortization (311) (220) Storm damage reserves (34) (34) Other, net 125 121 --------------------------------------------------------------- Total $ 646 $ 721 =============================================================== In the event that a portion of a company's operations is no longer subject to the provisions of FASB Statement No. 71, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value. Revenues and Fuel Costs Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. Electric rates for the operating companies include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between II-26 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report recoverable fuel costs and amounts actually recovered in current regulated rates. Southern Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues. Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $133 million in 2001, $136 million in 2000, and $137 million in 1999. Alabama Power and Georgia Power have contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in January 1998 as required by the contracts, and the companies are pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Farley to maintain full-core discharge capability until the refueling outages scheduled for 2006 and 2008 for units 1 and 2, respectively. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. At Plant Hatch, an on-site dry storage facility became operational in 2000. Sufficient dry storage capacity is believed to be available to continue dry storage operations at Plant Hatch through the life of the plant. Procurement of on-site dry storage capacity at Plant Farley is in progress, with the intent to place the capacity in operation in 2005. Procurement of on-site dry storage capacity at Plant Vogtle will begin in sufficient time to maintain pool full-core discharge capability. Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. Alabama Power and Georgia Power -- based on its ownership interests -- estimate their respective remaining liability at December 31, 2001, under this law to be approximately $21 million and $16 million. These obligations are recorded in the Consolidated Balance Sheets. Depreciation and Nuclear Decommissioning Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.4 percent a year in 2001, 2000, and 1999. 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. Depreciation expense includes an amount for the expected costs of decommissioning nuclear facilities and removal of other facilities. Georgia Power recorded accelerated amortization and depreciation amounting to $91 million in 2001, $135 million in 2000, and $85 million in 1999. See Note 3 under "Georgia Power Retail Rate Orders" for additional information. The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial nuclear power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. Alabama Power and Georgia Power have external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the respective state public service commissions. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. Site study cost is the estimate to decommission a specific facility as of the site study year, and ultimate cost is the estimate to decommission a specific facility as of its retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs -- based on the most current study as II-27 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report of December 31, 2001, for Alabama Power's Plant Farley and Georgia Power's ownership interests in plants Hatch and Vogtle were as follows: Plant Plant Plant Farley Hatch Vogtle ---------------------------------------------------------------- Site study basis (year) 1998 2000 2000 Decommissioning periods: Beginning year 2017 2014 2027 Completion year 2031 2042 2045 ---------------------------------------------------------------- (in millions) Site study costs: Radiated structures $629 $486 $420 Non-radiated structures 60 37 48 ---------------------------------------------------------------- Total $689 $523 $468 ================================================================ (in millions) Ultimate costs: Radiated structures $1,868 $1,004 $1,468 Non-radiated structures 178 79 166 ---------------------------------------------------------------- Total $2,046 $1,083 $1,634 ================================================================ Significant assumptions: Inflation rate 4.5% 4.7% 4.7% Trust earning rate 7.0 6.5 6.5 ---------------------------------------------------------------- The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. Annual provisions for nuclear decommissioning are based on an annuity method as approved by the respective state public service commissions. The amount expensed in 2001 and fund balances were as follows: Plant Plant Plant Farley Hatch Vogtle ----------------------------------------------------------------- (in millions) Amount expensed in 2001 $ 18 $ 20 $ 9 Accumulated provisions: External trust funds, at fair value $318 $229 $135 Internal reserves 36 20 12 ----------------------------------------------------------------- Total $354 $249 $147 ================================================================= Alabama Power's decommissioning costs for ratemaking are based on the site study. Effective January 1, 2002, the Georgia Public Service Commission (GPSC) decreased Georgia Power's annual provision for decommissioning expenses to $8 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2000. The estimates are $383 million and $282 million for plants Hatch and Vogtle, respectively. The ultimate costs associated with the 2000 NRC minimum funding requirements are $823 million and $1.03 billion for plants Hatch and Vogtle, respectively. Alabama Power and Georgia Power expect their respective state public service commissions to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning. In January 2002, Georgia Power received NRC approval for a 20-year extension of the license at Plant Hatch, which would permit the operation of units 1 and 2 until 2034 and 2038, respectively. The decommissioning costs disclosed above do not reflect this extension. Income Taxes Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of funds capitalized was $67 million in 2001, $71 million in 2000, and $36 million in 1999. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed. The cost of replacements of property -- exclusive of minor items of property -- is capitalized. Leveraged Leases Southern Company has several leveraged lease agreements -- ranging up to 30 years -- that relate to international energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization and for interest on long-term debt related to these investments. II-28 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report Southern Company's net investment in leveraged leases consists of the following at December 31: 2001 2000 ------------------------------------------------------------------ (in millions) Net rentals receivable $1,430 $1,430 Unearned income (775) (834) ------------------------------------------------------------------ Investment in leveraged leases 655 596 Deferred taxes arising from leveraged leases (193) (128) ------------------------------------------------------------------ Net investment in leveraged leases $ 462 $ 468 ================================================================== A summary of the components of income from leveraged leases is as follows: 2001 2000 1999 ------------------------------------------------------------------ (in millions) Pretax leveraged lease income $59 $61 $28 Income tax expense 21 21 10 ------------------------------------------------------------------ Income from leveraged leases $38 $40 $18 ================================================================== Impairment of Long-Lived Assets and Intangibles Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is reevaluated when circumstances or events change. Cash and Cash Equivalents For purposes of the consolidated financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Comprehensive Income Comprehensive income -- consisting of net income and changes in the fair value of marketable securities and qualifying cash flow hedges, net of income taxes -- is presented in the consolidated financial statements. Also, comprehensive income from discontinued operations includes foreign currency translation adjustments, net of income taxes. 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. Financial Instruments Effective January 2001, Southern Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The impact on net income was immaterial. Southern Company uses derivative financial instruments to hedge exposures to fluctuations in interest rates, foreign currency exchange rates, and certain commodity prices. Gains and losses on qualifying hedges are deferred and recognized either in income or as an adjustment to the carrying amount of the hedged item when the transaction occurs. At December 31, 2001, Southern Company had $450 million notional amount of interest rate swaps outstanding with deferred gains of $12 million. Southern 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 operating companies and Southern Power enter into commodity related forward and option contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of Southern Company's bulk energy purchases and sales contracts meet the definition of a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. In many cases, these fuel and electricity contracts qualify for normal purchase and sale exceptions under Statement No. 133 and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses, and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in II-29 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report net income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income. Southern Company has firm purchase commitments for equipment that require payment in euros. As a hedge against fluctuations in the exchange rate for euros, the company entered into forward currency swaps. The total notional amount is 48 million euros maturing in 2002 and 2003. At December 31, 2001, the gain on these swaps was less than $1 million. Other Southern Company financial instruments for which the carrying amount did not equal fair value at December 31 were as follows: Carrying Fair Amount Value ---------------------------------------------------------------- (in millions) Long-term debt: At December 31, 2001 $8,634 $8,693 At December 31, 2000 7,815 7,702 Capital and preferred securities: At December 31, 2001 2,276 2,282 At December 31, 2000 2,246 2,190 ---------------------------------------------------------------- The fair values for long-term debt and capital and preferred securities were based on either closing market price or closing price of comparable instruments. 2. RETIREMENT BENEFITS Southern Company has a defined benefit, trusteed, pension plan that covers substantially all employees. Also, Southern Company provides certain medical care and life insurance benefits for retired employees. The operating companies fund trusts to the extent required by their respective regulatory commissions. In late 2000, Southern Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees. The measurement date for plan assets and obligations is September 30 for each year. The following disclosures exclude discontinued operations. Pension Plan Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations ---------------------- 2001 2000 ---------------------------------------------------------------- (in millions) Balance at beginning of year $3,397 $3,248 Service cost 104 96 Interest cost 260 239 Benefits paid (176) (159) Plan amendments 173 4 Actuarial (gain) loss 2 (31) ---------------------------------------------------------------- Balance at end of year $3,760 $3,397 ================================================================ Plan Assets ---------------------- 2001 2000 ---------------------------------------------------------------- (in millions) Balance at beginning of year $6,157 $5,266 Actual return on plan assets (889) 1,030 Benefits paid (159) (139) ---------------------------------------------------------------- Balance at end of year $5,109 $6,157 ================================================================ The accrued pension costs recognized in the Consolidated Balance Sheets were as follows: 2001 2000 ------------------------------------------------------------------ (in millions) Funded status $ 1,349 $ 2,760 Unrecognized transition obligation (51) (63) Unrecognized prior service cost 269 116 Unrecognized net gain (1,020) (2,415) ------------------------------------------------------------------ Prepaid asset recognized in the Consolidated Balance Sheets $ 547 $ 398 ================================================================== Components of the pension plan's net periodic cost were as follows: 2001 2000 1999 ---------------------------------------------------------------- (in millions) Service cost $ 104 $ 96 $ 97 Interest cost 260 239 215 Expected return on plan assets (423) (384) (348) Recognized net gain (73) (62) (40) Net amortization 8 - (2) ---------------------------------------------------------------- Net pension cost (income) $(124) $(111) $ (78) ================================================================ II-30 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations ---------------------- 2001 2000 ----------------------------------------------------------------- (in millions) Balance at beginning of year $1,052 $ 980 Service cost 22 18 Interest cost 88 76 Benefits paid (54) (43) Plan amendments 186 69 Actuarial (gain) loss (55) (48) ----------------------------------------------------------------- Balance at end of year $1,239 $1,052 ================================================================= Plan Assets -------------------- 2001 2000 ----------------------------------------------------------------- (in millions) Balance at beginning of year $459 $395 Actual return on plan assets (59) 47 Employer contributions 79 59 Benefits paid (54) (42) ----------------------------------------------------------------- Balance at end of year $425 $459 ================================================================= The accrued postretirement costs recognized in the Consolidated Balance Sheets were as follows: 2001 2000 ----------------------------------------------------------------- (in millions) Funded status $(814) $(593) Unrecognized transition obligation 174 189 Unrecognized prior service cost 239 66 Unrecognized net loss (gain) (9) (53) Fourth quarter contributions 41 35 ----------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $(369) $(356) ================================================================= Components of the postretirement plan's net periodic cost were as follows: 2001 2000 1999 -------------------------------------------------------------- (in millions) Service cost $ 22 $ 18 $ 21 Interest cost 88 76 68 Expected return on plan assets (40) (34) (26) Recognized net gain - - 2 Net amortization 26 18 15 -------------------------------------------------------------- Net postretirement cost $ 96 $ 78 $ 80 ============================================================== The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits plan were: 2001 2000 ----------------------------------------------------------------- Discount 7.50% 7.50% Annual salary increase 5.00 5.00 Long-term return on plan assets 8.50 8.50 ----------------------------------------------------------------- An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 9.25 percent for 2001 decreasing gradually to 5.25 percent through the year 2010, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2001, as follows: 1 Percent 1 Percent Increase Decrease ------------------------------------------------------------------ (in millions) Benefit obligation $111 $97 Service and interest costs 10 9 ------------------------------------------------------------------ Employee Savings Plan Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2001, 2000, and 1999 were $51 million, $49 million, and $46 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. In the opinion of management, after consultation with legal counsel, the ultimate disposition of these matters is not expected to have a material adverse effect on Southern Company's financial condition. Georgia Power Potentially Responsible Party Status Georgia Power 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. Georgia II-31 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report Power has recognized $33 million in cumulative expenses through December 31, 2001 for the assessment and anticipated cleanup of sites on the Georgia Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia, that is listed on the federal National Priorities List. Georgia Power has contributed to the removal and remedial investigation and feasibility study costs for the site. Additional claims for recovery of natural resource damages at the site are anticipated. As of December 31, 2001, Georgia Power had recorded approximately $6 million in cumulative expenses associated with Georgia Power's agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site. The final outcome of each of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of Georgia Power's activities relating to these sites, management does not believe that the company's cumulative liability at these sites would be material to the financial statements. Environmental Litigation On November 3, 1999, the EPA brought a civil action in U.S. District Court in Georgia against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal-burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add Gulf Power and Mississippi Power based on lack of jurisdiction over those companies. The court directed the EPA to refile its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. The EPA refiled those claims as directed by the court. Also, the EPA refiled its claims against Alabama Power in U.S. District Court in Alabama. It has not refiled against Gulf Power, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case could have a significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and Savannah Electric have opposed that motion. Southern Company believes that its operating companies complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. Mobile Energy Services' Petition for Bankruptcy Mobile Energy Services Holdings (MESH), a subsidiary of Southern Company, is the owner and operator of a facility that generates electricity, produces steam, and processes black liquor as part of a pulp and paper complex in Mobile, Alabama. On January 14, 1999, MESH filed a petition for Chapter 11 bankruptcy relief in the U.S. Bankruptcy Court. This action was in response to Kimberly-Clark Tissue II-32 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report Company's (Kimberly-Clark) announcement in May 1998 of plans to close its pulp mill, effective September 1, 1999. The pulp mill had historically provided 50 percent of MESH's revenues. As a result of settlement discussions with Kimberly-Clark and MESH's bondholders, Southern Company recorded in 1999 a $69 million after-tax write down of its investment in MESH. Southern Company recorded an additional $10 million after-tax write down in 2000. At December 31, 2001, MESH had total assets of $359 million and senior debt outstanding of $190 million of first mortgage bonds and $72 million related to tax-exempt bonds. In connection with the bond financings, Southern Company provided certain limited guarantees, in lieu of funding debt service and maintenance reserve accounts with cash. As of December 31, 2001, Southern Company had paid the full $41 million pursuant to the guarantees. Southern Company continues to have guarantees outstanding of certain potential environmental and other obligations of MESH that represent a maximum contingent liability of $19 million at December 31, 2001. Mirant has agreed to indemnify Southern Company for any future obligations incurred under such guarantees. On August 4, 2000, MESH filed a proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed plan of reorganization was most recently amended on October 15, 2001. Southern Company expects that approval of a plan of reorganization would result in either a termination of Southern Company's ownership interest in MESH or the exchange of all assets of MESH for the cancellation of securities held by the bondholders but would not affect Southern Company's continuing guarantee obligations discussed earlier. The final outcome of this matter cannot now be determined. California Electricity Markets Litigation Prior to the spin off of Mirant, Southern Company was named as a defendant in two lawsuits filed in the superior courts of California alleging that certain owners of electric generation facilities in California, including Southern Company, engaged in various unlawful and anticompetitive acts that served to manipulate wholesale power markets and inflate wholesale electricity prices in California. One lawsuit naming Southern Company, Mirant, and other generators as defendants alleged that, as a result of the defendants' conduct, customers paid approximately $4 billion more for electricity than they otherwise would have and sought an award of treble damages, as well as other injunctive and equitable relief. The other suit likewise sought treble damages and equitable relief. The allegations in the two lawsuits in which Southern Company was named seemed to be directed to activities of subsidiaries of Mirant. On September 28 and November 6, 2001, the plaintiffs voluntarily dismissed Southern Company without prejudice from the two lawsuits in which it had been named as a defendant. Prior to being dismissed, Southern Company had notified Mirant of its claim for indemnification for costs associated with the lawsuits under the terms of the master separation agreement that governs the spin off of Mirant. Mirant had undertaken the defense of the lawsuits. Plaintiffs would not be barred by their own dismissal from naming Southern Company in some future lawsuit, but management believes that the likelihood of Southern Company having to pay damages in any such lawsuit is remote. Race Discrimination Litigation On July 28, 2000, a lawsuit alleging race discrimination was filed by three Georgia Power employees against Georgia Power, Southern Company, and the system service company in the Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit was removed to the United States District Court for the Northern District of Georgia. The lawsuit also raised claims on behalf of a purported class. The plaintiffs seek compensatory and punitive damages in an unspecified amount, as well as injunctive relief. On August 14, 2000, the lawsuit was amended to add four more plaintiffs. Also, an additional subsidiary of Southern Company, Southern Company Energy Solutions, Inc., was named a defendant. On October 11, 2001, the district court denied the plaintiffs' motion for class certification. The plaintiffs filed a motion to reconsider the order denying class certification, and the court denied the plaintiffs' motion to reconsider. On December 28, 2001, the plaintiffs filed a petition in the United States Court of Appeals for the Eleventh Circuit seeking permission to file an appeal of the October 11 decision. The defendants filed a brief in opposition of the petition on January 18, 2002. Discovery of the seven named plaintiffs' individual claims that remain in the case is ongoing. The final outcome of the case cannot now be determined. Alabama Power Rate Adjustment Procedures In November 1982, the Alabama Public Service Commission (APSC) adopted rates that provide for periodic adjustments based upon Alabama Power's earned return on end-of-period retail common equity. The rates also provide for adjustments to recognize the placing of new generating facilities in retail service. Both increases and decreases have been placed into effect since the adoption of these rates. Most recently, a 2 percent increase in retail rates was effective in II-33 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report October 2001, in accordance with the Rate Stabilization Equalization plan. The rate adjustment procedures allow a return on common equity range of 13 percent to 14.5 percent and limit increases or decreases in rates to 4 percent in any calendar year and prohibits two consecutive quarterly adjustments in the same direction. In December 1995, the APSC issued an order authorizing Alabama Power to reduce balance sheet items -- such as plant and deferred charges -- at any time the company's actual base rate revenues exceed the budgeted revenues. During the years 2001, 2000, and 1999, Alabama Power did not record any such reductions. The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them. Georgia Power Retail Rate Orders On December 20, 2001, the GPSC approved a three-year retail rate order for Georgia Power ending December 31, 2004. Under the terms of the order, earnings will be evaluated against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will be applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates were decreased by $118 million effective January 1, 2002. Under a previous three-year order ending December 2001, Georgia Power's earnings were evaluated against a retail return on common equity range of 10 percent to 12.5 percent. The order further provided for $85 million in each year, plus up to $50 million of any earnings above the 12.5 percent return during the second and third years, to be applied to accelerated amortization or depreciation of assets. Two-thirds of additional earnings above the 12.5 percent return were applied to rate refunds, with the remaining one-third retained by Georgia Power. Pursuant to the order, Georgia Power recorded $336 million of accelerated amortization and interest thereon, which has been credited to a regulatory liability account as mandated by the GPSC. Under the new rate order, the accelerated amortization and the interest will be amortized equally over three years as a credit to expense beginning in 2002. Effective January 1, 2002, Georgia Power discontinued recording accelerated depreciation and amortization. Georgia Power will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. Georgia Power is required to file a general rate case on July 1, 2004, in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued. In 2000 and 1999, Georgia Power recorded $44 million and $79 million, respectively, of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity. Refunds applicable to 2000 and 1999 were made to customers in 2001 and 2000, respectively. 4. JOINT OWNERSHIP AGREEMENTS Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities jointly with Alabama Electric Cooperative, Inc. Georgia Power owns undivided interests in plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia, the city of Dalton, Georgia, Florida Power &Light Company (FP&L), and Jacksonville Electric Authority (JEA). In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Florida Power Corporation (FPC) for a combustion turbine unit at Intercession City, Florida. Southern Power owns an undivided interest in Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. The unit is scheduled to go into commercial operation in October 2003. At December 31, 2001, Alabama Power's and Georgia Power's ownership and investment (exclusive of nuclear fuel) in jointly owned facilities with the above entities were as follows: Jointly Owned Facilities ------------------------------------------ Percent Amount of Accumulated Ownership Investment Depreciation ------------------------------------------ (in millions) Plant Vogtle (nuclear) 45.7% $3,304 $1,793 Plant Hatch (nuclear) 50.1 881 668 Plant Miller (coal) Units 1 and 2 91.8 747 326 Plant Scherer (coal) Units 1 and 2 8.4 112 56 Plant Wansley (coal) 53.5 309 152 Rocky Mountain (pumped storage) 25.4 169 78 Intercession City (combustion turbine) 33.3 12 1 Plant Stanton (combined cycle) Unit A 65.0 31 - ----------------------------------------------------------------- II-34 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities -- except for the Rocky Mountain project and Intercession City -- as agents for their respective co-owners. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the Consolidated Statements of Income. 5. LONG-TERM POWER SALES AND LEASE AGREEMENTS The operating companies have long-term contractual agreements for the sale and lease of capacity to certain non-affiliated utilities located outside the system's service area. These agreements are firm and are related to specific generating units. Because the energy is generally provided at cost under these agreements, profitability is primarily affected by capacity revenues. Unit power from specific generating plants is currently being sold to FP&L, FPC, and JEA. Under these agreements, approximately 1,500 megawatts of capacity is scheduled to be sold annually unless reduced by FP&L, FPC, and JEA for the periods after 2001 with a minimum of three years notice -- until the expiration of the contracts in 2010. Capacity revenues from unit power sales amounted to $170 million in 2001, $177 million in 2000, and $174 million in 1999. Southern Power and Mississippi Power have operating leases for portions of their generating unit capacity. Capacity revenues from these operating leases amounted to $53 million in 2001 and $20 million in 2000. These amounts are included in the financial statements as sales for resale. Minimum future capacity receipts from noncancelable operating leases as of December 31, 2001, are as follows: Year Amounts ---- ---------------- (in millions) 2002 $ 64 2003 65 2004 64 2005 23 2006 21 2007 and thereafter 97 ------------------------------------------------------------------ Total $334 ================================================================== 6. INCOME TAXES At December 31, 2001, the tax-related regulatory assets and liabilities were $924 million and $500 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. The following tables and disclosures exclude discontinued operations. Details of income tax provisions are as follows: 2001 2000 1999 ----------------------------------------------------------------- (in millions) Total provision for income taxes: Federal -- Current $477 $421 $504 Deferred (10) 95 11 ----------------------------------------------------------------- 467 516 515 ----------------------------------------------------------------- State -- Current 103 71 85 Deferred (12) 1 (1) ----------------------------------------------------------------- 91 72 84 ----------------------------------------------------------------- Total $558 $588 $599 ================================================================= 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: 2001 2000 --------------------------------------------------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $3,222 $3,199 Property basis differences 1,059 1,105 Other 739 650 --------------------------------------------------------------- Total 5,020 4,954 --------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 116 111 Other property basis differences 178 206 Deferred costs 234 190 Pension and other benefits 123 125 Other 304 231 --------------------------------------------------------------- Total 955 863 --------------------------------------------------------------- Total deferred tax liabilities, net 4,065 4,091 Portion included in current assets (liabilities), net 23 (17) --------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheets $4,088 $4,074 =============================================================== In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Consolidated Statements of Income. Credits amortized in this manner amounted to $30 million a year in 2001, 2000, and 1999. At December 31, 2001, all investment tax credits available to reduce federal income taxes payable had been utilized. II-35 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. Federal statutory rate to earnings before income taxes and preferred dividends of subsidiaries, as a result of the following: 2001 2000 1999 ---------------------------------------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.7 3.4 3.8 Alternative fuel tax credits (4.2) (1.3) (0.7) Non-deductible book depreciation 1.7 1.7 1.9 Difference in prior years' deferred and current tax rate (1.1) (1.3) (1.3) Other (2.2) (0.8) 0.4 ---------------------------------------------------------------- Effective income tax rate 32.9% 36.7% 39.1% ================================================================ Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability. Mirant was included in the consolidated federal tax return through April 2, 2001. Under the terms of the separation agreement, Mirant will indemnify Southern Company for subsequent assessment of any additional taxes related to its transactions prior to the spin off. 7. COMMON STOCK Stock Issued and Repurchased Southern Company issued 17 million and 5 million treasury shares of common stock in 2001 and 2000, respectively, through various company stock plans. Proceeds were $395 million in 2001 and $140 million in 2000. The shares were issued through various company stock plans. At December 31, 2001, approximately 2 million treasury shares remain unissued. In December 2000, Southern Company issued 28 million treasury shares of common stock through a public offering. The offering, which included an overallotment of 3 million shares, raised some $800 million and was priced at $28.50 per share. The proceeds were used to repay short-term commercial paper. In April 1999, Southern Company's Board of Directors approved the repurchase of up to 50 million shares of Southern Company's common stock over a two-year period through open market or privately negotiated transactions. Under this program, 50 million shares were repurchased by February 2000 at an average price of $25.53 per share. Shares Reserved At December 31, 2001, a total of 76 million shares was reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (stock option plan). Stock Option Plan Southern Company provides non-qualified stock options to a large segment of its employees ranging from line management to executives. As of December 31, 2001, 5,622 current and former employees participated in the stock option plan. The maximum number of shares of common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the plan. Stock option data for the plan has been adjusted to reflect the Mirant spin off. Activity in 2000 and 2001 for the plan is summarized below: Shares Average Subject Option Price To Option Per Share ---------------------------------------------------------------- Balance at December 31, 1999 13,419,978 $14.97 Options granted 11,042,626 14.67 Options canceled (335,282) 14.87 Options exercised (1,560,695) 13.65 ---------------------------------------------------------------- Balance at December 31, 2000 22,566,627 14.92 Options granted 13,623,210 20.31 Options canceled (3,397,152) 15.39 Options exercised (3,161,800) 13.83 ---------------------------------------------------------------- Balance at December 31, 2001 29,630,885 $17.46 ================================================================ Shares reserved for future grants: At December 31, 1999 54,684,999 At December 31, 2000 43,955,368 At December 31, 2001 64,795,653 --------------------------------------------------------------- Options exercisable: At December 31, 2000 9,354,705 At December 31, 2001 11,965,858 --------------------------------------------------------------- Southern Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized. II-36 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report The following table summarizes information about options outstanding at December 31, 2001: Dollar Price Range of Options ------------------------- 11-15 15-20 20-24 ---------------------------------------------------------------- Outstanding: Shares (in thousands) 11,742 12,882 5,007 Average remaining life (in years) 6.7 7.7 9.1 Average exercise price $14.38 $18.34 $22.43 Exerciseable: Shares (in thousands) 6,694 5,027 245 Average exercise price $14.17 $17.46 $22.42 ---------------------------------------------------------------- The estimated fair values of stock options granted in 2001, 2000, and 1999 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options: 2001 2000 1999 ------------------------------------------------------------------ Interest rate 4.8% 6.7% 5.8% Average expected life of stock options (in years) 4.3 4.0 3.7 Expected volatility of common stock 25.4% 20.9% 20.7% Expected annual dividends on common stock $1.34 $1.34 $1.34 Weighted average fair value of stock options granted $2.82 $3.36 $4.61 ------------------------------------------------------------------ The pro forma impact of fair-value accounting for options granted on earnings is as follows: Net Earnings Year Income Per Share ---- -------------- ------------- (in millions) (cents) 2001 $17 2.4 2000 8 1.3 1999 5 0.7 ----------------------------------------------------------------- Diluted Earnings Per Share For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to outstanding options under the stock option plan. The effect of the stock options was determined using the treasury stock method. Shares used to compute diluted earnings per share are as follows: Average Common Stock Shares -------------------------------- 2001 2000 1999 ---------------------------------------------------------------- (in thousands) As reported shares 689,352 653,087 685,163 Effect of options 4,191 1,018 530 ---------------------------------------------------------------- Diluted shares 693,543 654,105 685,693 ================================================================ Common Stock Dividend Restrictions The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2001, consolidated retained earnings included $3.4 billion of undistributed retained earnings of the subsidiaries. Of this amount, $2.1 billion was restricted against the payment by the subsidiary companies of cash dividends on common stock under terms of bond indentures. However, Georgia Power expects to discharge its first mortgage bond indenture in early 2002 and to be released from all indenture requirements. The $2.1 billion restriction includes $1.0 billion for Georgia Power under the current indenture requirements. 8. FINANCING Capital and Preferred Securities Company or subsidiary obligated mandatorily redeemable capital and preferred securities have been issued by special purpose financing entities of Southern Company and its subsidiaries. Substantially all the assets of these special financing entities are junior subordinated notes issued by the related company seeking financing. Each of these companies considers that the mechanisms and obligations relating to the capital or preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective special financing entities' payment obligations with respect to the capital or preferred securities. At December 31, 2001, capital securities of $950 million and preferred securities of $1.3 billion were outstanding and recognized in the Consolidated Balance Sheets. Southern Company guarantees the notes related to $950 million of capital or preferred securities issued on its behalf. II-37 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report Long-Term Debt Due Within One Year A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows: 2001 2000 ----------------------------------------------------------------- (in millions) Bond improvement fund requirements $ 5 $11 Less: Portion to be satisfied by certifying property additions 1 11 ----------------------------------------------------------------- Cash requirements 4 - First mortgage bond maturities and redemptions 3 - Other long-term debt maturities 422 67 ----------------------------------------------------------------- Total $429 $67 ================================================================= The first mortgage bond improvement fund requirements amount to 1 percent of each outstanding series of bonds authenticated under the indentures prior to January 1 of each year, other than those issued to collateralize pollution control revenue bonds and other obligations. The requirements may be satisfied by depositing cash or reacquiring bonds, or by pledging additional property equal to 1662/3 percent of such requirements. With respect to the collateralized pollution control revenue bonds, the operating companies have authenticated and delivered to trustees a like principal amount of first mortgage bonds as security for obligations under installment sale or loan agreements. The principal and interest on the first mortgage bonds will be payable only in the event of default under the agreements. Improvement fund requirements and/or serial maturities through 2006 applicable to total long-term debt are as follows: $429 million in 2002; $1.1 billion in 2003; $894 million in 2004; $399 million in 2005; and $226 million in 2006. Assets Subject to Lien Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. The subsidiary companies' mortgages, which secure the first mortgage bonds issued by the companies, constitute a direct first lien on substantially all of the companies' respective fixed property and franchises. Georgia Power expects to discharge its mortgage in early 2002 and that the lien will be removed. There are no agreements or other arrangements among the subsidiary companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. Bank Credit Arrangements At the beginning of 2002, unused credit arrangements with banks totaled $5.1 billion, of which $3.7 billion expires during 2002, $500 million expires during 2003, and $900 million expires during 2004. The following table outlines the credit arrangements by company: Amount of Credit ---------------------------- Expires --------------- 2003 & Company Total Unused 2002 beyond -------------------------------------------------------------- (in millions) Alabama Power $ 964 $ 964 $ 574 $ 390 Georgia Power 1,765 1,765 1,265 500 Gulf Power 103 103 103 - Mississippi Power 115 115 110 5 Savannah Electric 66 66 46 20 Southern Company 1,500 1,500 1,500 - Southern Power 850 557 - 557 Other 60 60 60 - -------------------------------------------------------------- Total $5,423 $5,130 $3,658 $1,472 ============================================================== Approximately $2.9 billion of the credit facilities expiring in 2002 allows for term loans ranging from one to three years. Most of the agreements include stated borrowing rates but also allow for competitive bid loans. All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. These balances are not legally restricted from withdrawal. Included in the $5.1 billion of unused credit arrangements is $4.8 billion of syndicated credit arrangements that require the payment of agent fees. A portion of the $5.1 billion unused credit with banks is allocated to provide liquidity support to the companies' variable rate pollution control bonds. The amount of variable rate pollution control bonds requiring liquidity support as of December 31, 2001 was $1.6 billion. Southern Company and the operating companies borrow through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the companies from time to time borrow under uncommitted lines of credit with banks. The amount of commercial paper outstanding at December 31, 2001 was $1.8 billion. II-38 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report 9. COMMITMENTS Construction Program Southern Company is engaged in continuous construction programs, currently estimated to total $2.8 billion in 2002, $2.1 billion in 2003, and $2.3 billion in 2004. The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2001, significant purchase commitments were outstanding in connection with the construction program. Southern Company has approximately 4,500 megawatts of additional generating capacity scheduled to be placed in service by 2003, of which 3,900 megawatts will be competitive generation assets. See Management's Discussion and Analysis under "Environmental Matters" for information on the impact of the Clean Air Act Amendments of 1990 and other environmental matters. Fuel and Purchased Power Commitments To supply a portion of the fuel requirements of the generating plants, Southern Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Natural gas purchases are based on various indices at the time of delivery; therefore, only the volume commitments are firm and disclosed in the following chart. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2001, were as follows: Natural Gas Purchased Year MMBtu Fuel Power ---- ------------ --------------------- (in millions) (in millions) 2002 163,595 $ 2,399 $ 97 2003 188,245 2,185 100 2004 118,245 1,541 95 2005 66,390 1,218 95 2006 49,085 1,155 95 2007 and thereafter 18,120 3,627 879 --------------------------------------------------------------- Total commitments 603,680 $12,125 $1,361 =============================================================== Operating Leases In May 2001, Mississippi Power began the initial 10-year term of a lease agreement signed in 1999 for a combined cycle generating facility built at Plant Daniel. The facility cost approximately $370 million. The lease provides for a residual value guarantee -- approximately 71 percent of the completion cost -- by Mississippi Power that is due upon termination of the lease in certain circumstances. The lease also includes purchase and renewal options. Upon termination of the lease, Mississippi Power may either exercise its purchase option of the facility or allow it to be sold to a third party. Mississippi Power expects the fair market value of the leased facility to substantially reduce or eliminate its payment under the residual value guarantee. The amount of future minimum operating lease payments exclusive of any payment related to this guarantee will be approximately $25 million annually during the initial term. Southern Company has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $64 million, $42 million, and $35 million for 2001, 2000, and 1999, respectively. At December 31, 2001, estimated minimum rental commitments for noncancelable operating leases were as follows: Year Amounts ---- -------------- (in millions) 2002 $ 74 2003 71 2004 70 2005 66 2006 58 2007 and thereafter 317 --------------------------------------------------------------- Total minimum payments $656 =============================================================== In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain rail car leases with respect to the residual value of the leased property. These leases expire in 2004, 2006, and 2010, and the maximum obligations are $39 million, $66 million, and $40 million, respectively. At the termination of the leases, the lessee may either exercise its purchase option or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations. II-39 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report Guarantees Southern Company has made separate guarantees to certain counterparties regarding performance of contractual commitments by Mirant's trading and marketing subsidiaries. At December 31, 2001, the total original notional amount of guarantees was $53 million, all of which will expire by 2007. Estimated fair value of these net contractual commitments outstanding was approximately $25 million. Under the terms of the separation agreement, Mirant may not enter into any new commitments under these guarantees after the spin off date. Based upon a statistical analysis of credit risk, Southern Company's potential exposure under these contractual commitments would not materially differ from the estimated fair value. Mirant will pay Southern Company a fee of 1 percent annually on the average aggregate maximum principal amount of all guarantees outstanding until they are replaced or expire. Mirant must use reasonable efforts to release Southern Company from all such support arrangements and will indemnify Southern Company for any obligations incurred. 10. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The act provides funds up to $9.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $200 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. A company could be assessed up to $88 million per incident for each licensed reactor it operates, but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power -- based on its ownership and buyback interests -- is $176 million and $178 million, respectively, per incident, but not more than an aggregate of $20 million per company to be paid for each incident in any one year. Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities. Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the three NEIL policies would be $35 million and $39 million, respectively. Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would be covered under their insurance. However, both companies revised their policy terms on a prospective basis to include an industry aggregate for all terrorist acts. The NEIL aggregate, which applies to all claims stemming from terrorism within a 12-month duration, is $3.24 billion plus any amounts that would be available through reinsurance or indemnity from an outside source. The ANI cap is $200 million in a policy year. 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. II-40 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report 11. DISCOUNTINUED OPERATIONS In April 2000, Southern Company announced an initial public offering of up to 19.9 percent of Mirant and its intentions to spin off the remaining ownership of Mirant to Southern Company stockholders within 12 months of the initial stock offering. On October 2, 2000, Mirant completed its initial public offering of 66.7 million shares of common stock priced at $22 per share. This represented 19.7 percent of the 338.7 million shares outstanding. As a result of the stock offering, Southern Company recorded a $560 million increase in paid-in capital with no gain or loss being recognized. On February 19, 2001, the Southern Company Board of Directors approved the spin off of its remaining ownership of 272 million Mirant shares. On April 2, 2001, the tax-free distribution of Mirant shares was completed at a ratio of approximately 0.4 for every share of Southern Company common stock held at record date. The distribution resulted in charges of approximately $3.2 billion and $0.4 billion to Southern Company's paid-in capital and retained earnings, respectively. The distribution was treated as a non-cash transaction for purposes of the statement of cash flows. As a result of the spin off, Southern Company's financial statements reflect Mirant's results of operations, balance sheets, and cash flows as discontinued operations. Certain amounts in the cash flows related to intercompany eliminations for 2000 and 1999 have been reclassified from cash provided from operating activities to cash used for discontinued operations. Summarized financial information for the discontinued operations is as follows at December 31: 2001 2000 1999 ----------------------------------------------------------------- (in millions) Revenues $8,182 $13,315 $2,265 Income taxes 93 86 127 Net income 142 319 361 ----------------------------------------------------------------- 2000 ----------------------------------------------------------------- (in millions) Current assets $ 9,057 Total assets 22,377 Current liabilities 9,726 Total liabilities 17,585 Minority and other interests 1,472 Net assets of discontinued operations 3,320 ----------------------------------------------------------------- 12. SEGMENT AND RELATED INFORMATION Southern Company's reportable business segment is the sale of electricity in the Southeast by the five operating companies and Southern Power. Net income and total assets for discontinued operations are included in the reconciling eliminations column. The all other category includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include telecommunications, energy products and services, and leasing and financing services. Intersegment revenues are not material. Financial data for business segments and products and services are as follows: Business Segments
Electric All Reconciling Year Utilities Other Eliminations Consolidated ---- ----------------------------------------------------------------------------------- (in millions) 2001 ----- Operating revenues $ 9,906 $ 267 $ (18) $10,155 Depreciation and amortization 1,144 29 - 1,173 Interest income 21 8 (2) 27 Interest expense 591 137 (2) 726 Income taxes 702 (144) - 558 Segment net income (loss) 1,149 (30) 143 1,262 Total assets 29,389 2,420 (1,985) 29,824 Gross property additions 2,565 52 - 2,617 ----------------------------------------------------------------------------------------------------------------------------
II-41 NOTES (continued) Southern Company and Subsidiary Companies 2001 Annual Report
Electric All Reconciling Year Utilities Other Eliminations Consolidated ----- ------------------------------------------------------------------------------------ (in millions) 2000 ---- Operating revenues $ 9,860 $ 246 $ (40) $10,066 Depreciation and amortization 1,135 36 - 1,171 Interest income 21 7 1 29 Interest expense 615 197 - 812 Income taxes 703 (115) - 588 Segment net income (loss) 1,109 (115) 319 1,313 Total assets 26,820 2,200 2,240 31,260 Gross property additions 2,199 26 - 2,225 ---------------------------------------------------------------------------------------------------------------------------- Electric All Reconciling Year Utilities Other Eliminations Consolidated ---- ------------------------------------------------------------------------------------ (in millions) 1999 ---- Operating revenues $ 9,125 $ 221 $ (29) $ 9,317 Depreciation and amortization 1,046 93 - 1,139 Interest income 23 5 2 30 Interest expense 585 155 (38) 702 Income taxes 675 76 - 599 Segment net income (loss) 1,073 (158) 361 1,276 Total assets 25,336 2,127 1,828 29,291 Gross property additions 1,854 27 - 1,881 ---------------------------------------------------------------------------------------------------------------------------- Products and Services Electric Utilities Revenues ------------------------------------------------------------------------------------ Year Retail Wholesale Other Total ---- ------------------------------------------------------------------------------------ (in millions) 2001 $8,440 $1,174 $292 $9,906 2000 8,600 977 283 9,860 1999 8,090 823 212 9,125 ------------------------------------------------------------------------------------------------------------------------
13. QUARTERLY FINANCIAL INFORMATION FOR CONTINUING OPERATIONS (UNAUDITED) Summarized quarterly financial data for 2001 and 2000 are as follows:
Per Common Share (Note) ----------------------------------------------------- Operating Operating Consolidated Basic Price Range Quarter Ended Revenues Income Net Income Earnings Dividends High Low -------------- ------------------------------------ ----------------------------------------------------- (in millions) March 2001 $2,270 $475 $180 $0.26 $0.335 $21.650 $16.152 June 2001 2,561 585 270 0.40 0.335 23.880 20.890 September 2001 3,165 998 554 0.80 0.335 26.000 22.050 December 2001 2,159 333 116 0.16 0.335 25.980 22.300 March 2000 $2,052 $ 428 $151 $0.23 $0.335 $25.875 $20.375 June 2000 2,522 598 256 0.39 0.335 27.875 21.688 September 2000 3,198 1,039 523 0.81 0.335 35.000 23.406 December 2000 2,294 340 64 0.09 0.335 33.880 27.500 ----------------------------------------------------------------------------------------------------------------------------- Southern Company's business is influenced by seasonal weather conditions. Note: Market price data in 2001 declined as a result of the Mirant spin off.
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Selected Consolidated Financial and Operating Data 1997-2001 Southern Company and Subsidiary Companies 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ----------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in millions) $10,155 $10,066 $9,317 $9,499 $8,774 Total Assets (in millions) $29,824 $31,260 $29,291 $28,723 $27,898 Gross Property Additions (in millions) $2,617 $2,225 $1,881 $1,356 $1,138 Return on Average Common Equity (percent) 13.51 13.20 13.43 10.04 10.30 Cash Dividends Paid Per Share of Common Stock $1.34 $1.34 $1.34 $1.34 $1.30 ----------------------------------------------------------------------------------------------------------------------------- Consolidated Net Income (in millions): Continuing operations $1,120 $ 994 $ 915 $986 $990 Discontinued operations 142 319 361 (9) (18) ----------------------------------------------------------------------------------------------------------------------------- Total $1,262 $1,313 $1,276 $977 $972 ============================================================================================================================= Earnings Per Share From Continuing Operations -- Basic $1.62 $1.52 $1.33 $1.41 $1.45 Diluted 1.61 1.52 1.33 1.41 1.45 Earnings Per Share Including Discontinued Operations -- Basic $1.83 $2.01 $1.86 $1.40 $1.42 Diluted 1.82 2.01 1.86 1.40 1.42 ----------------------------------------------------------------------------------------------------------------------------- Capitalization (in millions): Common stock equity $ 7,984 $10,690 $ 9,204 $ 9,797 $ 9,647 Preferred stock and securities 2,644 2,614 2,615 2,465 2,155 Long-term debt 8,297 7,843 7,251 6,505 6,347 ----------------------------------------------------------------------------------------------------------------------------- Total excluding amounts due within one year $18,925 $21,147 $19,070 $18,767 $18,149 ============================================================================================================================= Capitalization Ratios (percent): Common stock equity 42.2 50.6 48.3 52.2 53.2 Preferred stock and securities 13.9 12.3 13.7 13.1 11.9 Long-term debt 43.9 37.1 38.0 34.7 34.9 ----------------------------------------------------------------------------------------------------------------------------- Total excluding amounts due within one year 100.0 100.0 100.0 100.0 100.0 ============================================================================================================================= Other Common Stock Data (Note): Book value per share (year-end) $11.44 $15.69 $13.82 $14.04 $13.91 Market price per share: High $26.000 $35.000 $29.625 $31.563 $26.250 Low 16.152 20.375 22.063 23.938 19.875 Close 25.350 33.250 23.500 29.063 25.875 Market-to-book ratio (year-end) (percent) 221.6 211.9 170.0 207.0 186.0 Price-earnings ratio (year-end) (times) 15.6 16.5 12.6 20.8 18.2 Dividends paid (in millions) $922 $873 $921 $933 $889 Dividend yield (year-end) (percent) 5.3 4.0 5.7 4.6 5.0 Dividend payout ratio (percent) 82.4 66.5 72.2 95.6 91.5 Shares outstanding (in thousands): Average 689,352 653,087 685,163 696,944 685,033 Year-end 698,344 681,158 665,796 697,747 693,423 Stockholders of record (year-end) 150,242 160,116 174,179 187,053 200,508 ----------------------------------------------------------------------------------------------------------------------------- Customers (year-end) (in thousands): Residential 3,441 3,398 3,339 3,277 3,220 Commercial 539 527 513 497 479 Industrial 14 14 15 15 16 Other 4 5 4 5 5 ----------------------------------------------------------------------------------------------------------------------------- Total 3,998 3,944 3,871 3,794 3,720 ============================================================================================================================= Employees (year-end) 26,122 26,021 26,269 25,206 24,682 ----------------------------------------------------------------------------------------------------------------------------- Note: Common stock data in 2001 declined as a result of the Mirant spin off.
II-43
Selected Consolidated Financial and Operating Data 1997-2001 (continued) Southern Company and Subsidiary Companies 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------------------ Operating Revenues (in millions): Residential $ 3,247 $ 3,361 $3,107 $3,167 $2,836 Commercial 2,966 2,918 2,745 2,766 2,594 Industrial 2,144 2,289 2,238 2,268 2,138 Other 83 32 - 79 77 ------------------------------------------------------------------------------------------------------------------------------------ Total retail 8,440 8,600 8,090 8,280 7,645 Sales for resale within service area 338 377 350 374 376 Sales for resale outside service area 836 600 473 522 510 ------------------------------------------------------------------------------------------------------------------------------------ Total revenues from sales of electricity 9,614 9,577 8,913 9,176 8,531 Other revenues 541 489 404 323 243 ------------------------------------------------------------------------------------------------------------------------------------ Total $10,155 $10,066 $9,317 $9,499 $8,774 ==================================================================================================================================== Kilowatt-Hour Sales (in millions): Residential 44,538 46,213 43,402 43,503 39,217 Commercial 46,939 46,249 43,387 41,737 38,926 Industrial 52,891 56,746 56,210 55,331 54,196 Other 977 970 945 929 903 ------------------------------------------------------------------------------------------------------------------------------------ Total retail 145,345 150,178 143,944 141,500 133,242 Sales for resale within service area 9,388 9,579 9,440 9,847 9,884 Sales for resale outside service area 21,380 17,190 12,929 12,988 13,761 ------------------------------------------------------------------------------------------------------------------------------------ Total 176,113 176,947 166,313 164,335 156,887 ==================================================================================================================================== Average Revenue Per Kilowatt-Hour (cents): Residential 7.29 7.27 7.16 7.28 7.23 Commercial 6.32 6.31 6.33 6.63 6.66 Industrial 4.05 4.03 3.98 4.10 3.95 Total retail 5.81 5.73 5.62 5.85 5.74 Sales for resale 3.82 3.65 3.68 3.92 3.75 Total sales 5.46 5.41 5.36 5.58 5.44 Average Annual Kilowatt-Hour Use Per Residential Customer 13,014 13,702 13,107 13,379 12,296 Average Annual Revenue Per Residential Customer $948.83 $996.44 $938.39 $973.94 $889.29 Plant Nameplate Capacity Owned (year-end) (megawatts) 34,579 32,807 31,425 31,161 31,146 Maximum Peak-Hour Demand (megawatts): Winter 26,272 26,370 25,203 21,108 22,969 Summer 29,700 31,359 30,578 28,934 27,334 System Reserve Margin (at peak) (percent) 19.3 8.1 8.5 12.8 15.0 Annual Load Factor (percent) 62.0 60.2 59.2 60.0 59.4 Plant Availability (percent): Fossil-steam 88.1 86.8 83.3 85.2 88.2 Nuclear 90.8 90.5 89.9 87.8 88.8 ------------------------------------------------------------------------------------------------------------------------------------ Source of Energy Supply (percent): Coal 67.5 72.3 73.1 72.8 74.7 Nuclear 15.2 15.1 15.7 15.4 16.5 Hydro 2.6 1.5 2.3 3.9 4.3 Oil and gas 8.4 4.0 2.8 3.3 1.7 Purchased power 6.3 7.1 6.1 4.6 2.8 ------------------------------------------------------------------------------------------------------------------------------------ Total 100.0 100.0 100.0 100.0 100.0 ====================================================================================================================================
II-44 ALABAMA POWER COMPANY FINANCIAL SECTION II-45 MANAGEMENT'S REPORT Alabama Power Company 2001 Annual Report The management of Alabama Power Company has prepared -- and is responsible for -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements. The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship. The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. The audit committee of the board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time. Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics. In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of Alabama Power Company in conformity with accounting principles generally accepted in the United States. /s/Charles D. McCrary Charles D. McCrary President and Chief Executive Officer /s/William B. Hutchins, III William B. Hutchins, III Executive Vice President, Chief Financial Officer, and Treasurer February 13, 2002 II-46 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Alabama Power Company: We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements (pages II-58 through II-76) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2001, Alabama Power Company changed its method of accounting for derivative instruments and hedging activities. /s/Arthur Andersen LLP Birmingham, Alabama February 13, 2002 II-47 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 2001 Annual Report RESULTS OF OPERATIONS Earnings Alabama Power Company's 2001 net income after dividends on preferred stock was $387 million, representing a $33 million (7.9 percent) decrease from the prior year. This decline is primarily attributable to a decrease in territorial energy sales as a result of an economic downturn and milder temperatures. In 2000 earnings were $420 million, representing a 5 percent increase from the prior year. This improvement was primarily attributable to an increase in territorial sales partially offset by increased non-fuel operating expenses. The return on average common equity for 2001 was 11.89 percent compared to 13.58 percent in 2000 and 13.85 percent in 1999. Revenues Operating revenues for 2001 were $3.6 billion, reflecting a decrease from 2000. The following table summarizes the principal factors that have affected operating revenues for the past two years: Increase (Decrease) Amount From Prior Year -------------------------------------- 2001 2001 2000 ----------------------------------------------------------------- (in thousands) Retail -- Base revenues $2,033,814 $ (75,125) $ 80,264 Fuel cost recovery and other 713,859 (129,909) 61,326 ----------------------------------------------------------------- Total retail 2,747,673 (205,034) 141,590 ----------------------------------------------------------------- Sales for resale -- Non-affiliates 485,974 24,244 46,353 Affiliates 245,189 78,970 73,780 ----------------------------------------------------------------- Total sales for resale 731,163 103,214 120,133 Other operating revenues 107,554 20,749 20,264 ----------------------------------------------------------------- Total operating revenues $3,586,390 $ (81,071) $281,987 ================================================================= Percent change (2.21)% 8.33% ----------------------------------------------------------------- Retail revenues of $2.7 billion in 2001 decreased $205 million (6.9 percent) from the prior year, compared with an increase of $142 million (5 percent) in 2000. The primary contributors to the decrease in revenues in 2001 were the negative impact of milder temperatures on energy sales, an economic downturn in the Company's service territory, and a decrease in fuel revenues. Fuel revenues have no effect on net income because they represent the recording of revenues to offset fuel expenses. Fuel rates billed to customers are designed to fully recover fluctuating fuel costs over a period of time. Lower natural gas prices, an increased fuel rate, and increased hydro production combined with decreased costs of purchased power have resulted in a $154 million (65 percent) reduction in under-recovered fuel costs at December 31, 2001 compared with the prior year. The Company expects to continue to reduce the balance of $83 million during 2002. II-48 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report Other operating revenues in 2001 increased $21 million (23.9 percent) over 2000. This increase is primarily attributed to increased steam sales in conjunction with the operation of the Company's co-generation facilities, fuel sales, and rent from electric property. Since co-generation steam revenues are generally offset by fuel expenses, these revenues did not have a significant impact on earnings. The $20 million (30.5 percent) increase in other operating revenues in 2000 as compared to 1999 was due primarily to an increase in steam sales in conjunction with the operation of the Company's co-generation facilities. Energy sales for resale outside the service area are predominantly unit power sales under long-term contracts to Florida utilities. Economy energy and energy sold under short-term contracts are also sold for resale outside the service area. Revenues from long-term power contracts have both a capacity and energy component. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows: 2001 2000 1999 ------------------------------------------- (in millions) Capacity $125 $127 $122 Energy 134 128 112 ------------------------------------------------------------ Total $259 $255 $234 ============================================================ Capacity revenues from non-affiliates were relatively unchanged in 2001 compared to the prior two years. There are no scheduled declines in capacity until the termination of the contracts in 2010. Revenues from sales to affiliated companies within the Southern electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These transactions did not have a significant impact on earnings. Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as follows: KWH Percent Change ---------------------------------------- 2001 2001 2000 ---------------------------------------- (millions) Residential 15,881 (5.3)% 6.8% Commercial 12,799 (1.5) 5.5 Industrial 20,460 (7.4) 0.7 Other 198 (3.9) 2.3 ------------ Total retail 49,338 (5.2) 3.8 Sales for resale - Non-affiliates 15,278 2.9 19.4 Affiliates 8,843 64.7 6.7 ------------ Total 73,459 1.6 6.9 ----------------------------------------------------------------- Retail energy sales in 2001 decreased by 5.2 percent due to milder temperatures and an economic downturn in the Company's service area. This was offset by an increase in sales for resale to affiliates. Increased operation of the Company's combined cycle facilities due to lower natural gas prices and an increase in the Company's combined cycle capacity contributed to the increase in sales for resale. The increase in 2000 retail energy sales was primarily due to the strength of business and economic conditions in the Company's service area. Residential energy sales experienced a 6.8 percent increase over the prior year primarily as a result of warmer summer temperatures and cold winter weather conditions compared to 1999. Expenses In 2001 total operating expenses of $2.7 billion were down $50 million or 1.8 percent compared with 2000. This decline is mainly due to an $18 million net decrease in fuel and purchased power costs and a $56 million decrease in non-production operation and maintenance expenses, offset by a $19 million increase in depreciation. Fuel expenses, including purchased power, are offset by fuel revenues and have no effect on net income. In 2000 total operating expenses of $2.7 billion were up $235 million or 9.4 percent compared with the prior year. This increase was mainly due to a $183 million increase in fuel and purchased power costs, accompanied by a $23 million increase in maintenance expenses. II-49 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net KWH generated were as follows: -------------------------- 2001 2000 1999 -------------------------- Total generation (billions of KWHs) 68 65 63 Sources of generation (percent) -- Coal 64 72 72 Nuclear 18 19 20 Hydro 6 3 5 Oil & Gas 12 6 3 Average cost of fuel per net KWH generated (cents) -- 1.56 1.54 1.44 ============================================================== In 2001, total fuel and purchased power costs of $1.3 billion decreased $18 million (1.4 percent), while total energy sales increased 1,174 million kilowatt hours (1.6 percent) compared with the amounts recorded in 2000. Fuel and purchased power costs in 2000 increased $183 million (16 percent) compared to 1999. Purchased power consists of purchases from affiliates in the Southern electric system and non-affiliated companies. Purchased power transactions among the Company and its affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at each company. During 2001 purchased power transactions from non-affiliates decreased $20 million (12 percent) due to the addition in May 2001 of a combined cycle unit and an 82 percent increase in hydro generation compared to the previous year. The hydro generation increase occurred from greater stream flows in 2001 compared to the previous year. The 6 percent decrease in other operation expense in 2001 as compared to 2000 is primarily due to a decrease in administrative and general expenses, which can be mainly attributed to insurance refunds. The 8.5 percent decrease in maintenance expense in 2001 as compared to 2000 is primarily due to a decrease in power production expense as a result of timing of maintenance for steam power generation facilities. The 8.4 percent increase in maintenance expense in 2000 as compared to 1999 is primarily attributable to an increase in the maintenance of overhead distribution lines and additional accruals to partially replenish the natural disaster reserve. Depreciation and amortization expense increased 5.2 percent in 2001 and 4.9 percent in 2000. These increases reflect additions to property, plant, and equipment. Total net interest and other charges increased $10 million (4.0 percent) in 2001. The increase reflected a decrease in Allowance for Funds Used During Construction (AFUDC) resulting in a smaller credit to interest expense than was recorded in 2000. Total net interest and other charges increased $19 million (7.9 percent) in 2000 primarily from an increase in interest on long-term debt offset by an increase in AFUDC, which resulted in a larger credit to interest expense. Effects of Inflation The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed. Future Earnings Potential General The results of continuing operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors. The major factor is the ability of the Company to achieve energy sales growth while containing cost in a more competitive environment. Growth in energy sales is subject to a number of factors. These factors include weather, competition, new short- and long-term II-50 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area. Assuming normal weather, sales to retail customers are projected to grow approximately 2.4 percent annually on average during 2002 through 2006. The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the state of Alabama. Prices for electricity provided by the Company to retail customers are set by the Alabama Public Service Commission (APSC) under cost-based regulatory principles. Rates to retail customers served by the Company are regulated by the APSC. Rates for the Company can be adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return. The rates also provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP (Certificated New Plant). Effective July 2001, the Company's retail rates were adjusted by 0.6 percent under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into commercial operation on May 1, 2001. Most recently, a 2 percent increase in retail rates was effective in October 2001, in accordance with the Rate Stabilization Equalization plan. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional information. In December 1995, the APSC issued an order authorizing the Company to reduce balance sheet items-- such as plant and deferred charges -- at any time the Company's actual base rate revenues exceed the budgeted revenues. In April 2000, the APSC approved an amendment to the Company's existing rate structure to provide for the recovery of retail costs associated with certified purchased power agreements. In November 2000 the APSC certified a seven-year purchased power agreement pertaining to 615 megawatts of the wholesale generating facilities, which were sold to Southern Power in June 2001 and are under construction in Autaugaville, Alabama. All of the 615 megawatts will be delivered beginning in 2003. In addition the APSC certified a seven-year purchased power agreement with a third party for approximately 630 megawatts; one half of the power will be delivered beginning in 2003 while the remaining half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail rates when the contracted capacity delivery begins. In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income of approximately $57 million in 2001. Future pension income is dependent on several factors including trust earnings and changes to the plan. For the Company, pension income is a component of the regulated rates and does not have a significant effect on net income. For more information see Note 2 to the financial statements. The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings. Compliance costs related to current and future environmental laws, regulations, and litigation could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters." Industry Restructuring The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and/or commercial customers and sell excess energy generation to other utilities. Also, electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it was a major catalyst for the recent restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition. Among other things these initiatives allow customers to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and II-51 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report competition initiatives have been discussed in Alabama, none have been enacted. In October 2000 the APSC completed a two-year study of electric industry restructuring, concluding that (i) restructuring of the electric utility industry in Alabama was not in the public interest and (ii) the APSC itself would not mandate retail competition or electric industry restructuring without enabling state legislation. Electric utility restructuring would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California. As a result of that crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings. The Company had 1,230 megawatts of wholesale generating facilities under construction in 2001 at Autaugaville, Alabama. In June 2001 the Company sold this project to Southern Power Company, a new Southern Company subsidiary formed in 2001 to construct, own, and manage wholesale generating assets in the Southeast. The Company has entered into a purchased power agreement with Southern Power, through May 2010, for half of the capacity of these generating facilities. In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final ruling on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its operating companies, including the Company, have submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In January 2002 the sponsors of SeTrans held a public meeting to form a Stakeholder Advisory Committee, which will participate in the development of the RTO. Southern Company continues to work with the other sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to have a material impact on the Company's financial statements. The outcome of this matter cannot now be determined. Accounting Standards Critical Policy The Company's significant accounting policies are described in Note 1 to the financial statements. The Company's most critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operation is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information. New Accounting Standards Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Statement No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value, and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. See Note 1 to the financial statements under "Financial Instruments" for additional information. The impact on net income in 2001 was not material. An additional interpretation of Statement No. 133 will result in a change - effective April 1, 2002 - in accounting for certain contracts related to fuel supplies that contain quantity options. These contracts will be accounted for as derivatives and marked to market. However, due to the existence of the Company's cost-based fuel recovery clause, this change is not expected to have a material impact on net income. In June 2001 the FASB issued Statement No. 142, Goodwill and Other Intangible Assets, which establishes new accounting and reporting standards for acquired goodwill and other intangible assets and supersedes Accounting Principles Board Opinion No. 17. Statement No. 142 addresses how intangible assets that are II-52 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for upon acquisition and on an ongoing basis. Goodwill and intangible assets that have indefinite useful lives will not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives, which are no longer limited to 40 years. The Company adopted Statement No.142 in January 2002 with no material impact on the financial statements. Also in June 2001, the FASB issued Statement No. 143, Asset Retirement Obligations, which establishes new accounting and reporting standards for legal obligations associated with retiring assets, including decommissioning of nuclear plants. The liability for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The Company has not yet quantified the impact of adopting Statement No. 143 on its financial statements. FINANCIAL CONDITION Overview In 2001, despite significant cost control measures, the Company's earnings were adversely impacted by an economic downturn and milder temperatures. However, over the last several years the Company's financial condition has remained stable as a result of growth in retail energy sales and cost control measures combined with significant lowering of the cost of capital, achieved through the refinancing and/or redemption of higher-cost long-term debt and preferred stock. The Company had gross property additions of $636 million in 2001. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, principally from earnings and non-cash charges to income such as depreciation and deferred income taxes. The Statements of Cash Flows provide additional details. Credit Rating Risk The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. Exposure to Market Risk Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 2001, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows. Fair value of changes in energy trading contracts and year-end valuations are as follows: Changes During the Year ------------------ Fair Value --------------------------------------------------------------- (in thousands) Contracts beginning of year $ 567 Contracts realized or settled (509) New contracts at inception - Changes in valuation techniques - Current period changes 156 --------------------------------------------------------------- Contracts end of year $ 214 =============================================================== Source of Year-End Valuation Prices ------------------------------------ Maturity Total ---------------------- Fair Value Year 1 1-3 Years ------------------------------------------------------------------ (in thousands) ------------------------------------------------------------------ Actively quoted $(4,840) $(4,801) $(39) External sources 5,054 5,054 - Models and other methods - - - ------------------------------------------------------------------ Contracts end of Year $ 214 $ 253 $(39) ================================================================== Also, based on the Company's overall variable rate long-term debt exposure at December 31, 2001, a near-term 100 basis point change in interest rates would not materially affect the financial statements. For additional information, see Note 1 to the financial statements under "Financial Instruments." In October 2001, the APSC approved a revision to the Company's Rate ECR (Energy Cost Recovery) allowing the recovery of specific costs associated with II-53 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report the sales of natural gas that become necessary due to operating considerations at its electric generating facilities. This revision also includes the cost of financial tools used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Capital Structure The Company's ratio of common equity to total capitalization -- including short-term debt -- was 42.8 percent in 2001, 42.2 percent in 2000, and 42.4 percent in 1999. In August 2001, the Company issued $442 million of senior notes, the proceeds of which were used to redeem the $131.5 million outstanding principal of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other corporate purposes, including the repayment of a portion of its short-term indebtedness. Capital Requirements Capital expenditures are estimated to be $671 million for 2002, $592 million for 2003, and $673 million for 2004. See Note 4 to the financial statements for additional details. Actual construction costs may vary from estimates because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition there can be no assurance that costs related to capital expenditures will be fully recovered. Other Capital Requirements In addition to the funds required for the Company's construction program, approximately $1.1 billion will be required by the end of 2004 for present sinking fund requirements and maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit. These capital requirements, lease obligations, and purchase commitments - discussed in notes 4 and 8 to the financial statements - are as follows: 2002 2003 2004 ----------------------------------------------------------------- (in millions) Bonds - First mortgage $ 4.5 $ - $ - Pollution control - - - Senior Notes - 573.2 525.0 Leases - Capital 0.9 0.9 1.0 Operating 27.9 26.5 25.5 Purchase commitments - Fuel 795.0 794.0 801.0 Purchased Power - 53.0 83.0 ----------------------------------------------------------------- At the beginning of 2002, the Company had not used any of its available credit arrangements. Credit arrangements are as follows: Expires ---------------------------------- Total Unused 2002 2003 & Beyond ----------------------------------------------------------------- (in millions) $964 $964 $574 $390 ----------------------------------------------------------------- Environmental Matters In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Southern Company. Reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995. Southern Company achieved Phase I compliance at its affected plants by primarily switching to low-sulfur coal and with some equipment upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $25 million for the Company. Phase II sulfur dioxide compliance was required in 2000. The Company used emission allowances and fuel switching to comply with Phase II requirements. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits. Compliance with Phase II increased the Company's total construction expenditures through 2000 by $63 million. II-54 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report In December 2000, the Alabama Department of Environmental Management adopted revisions to the State Implementation Plan for meeting the one-hour ozone standard. New emission limits to comply with these requirements must be implemented in May 2003. Two generating plants will be affected in the Birmingham area. Capital expenditures for compliance with these new rules are currently estimated at approximately $240 million, of which $170 million remains to be spent. In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U. S. Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals is considering other legal challenges to these standards. A court decision is expected in the spring of 2002. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued nitrogen oxide reduction rules to the states for implementation. The final rule affects 21 states, including Alabama. Compliance is required by May 31, 2004 for most states including Alabama. Capital expenditures for compliance with these new rules are currently estimated at approximately $175 million. A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered. On November 3, 1999, the EPA brought a civil action against the Company in the U.S. District Court in Atlanta, Georgia. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000 the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and notice of violation allege that the Company had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. In August 2000, the U.S. District Court in Georgia granted the Company's motion to dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims against the Company in federal district court in Birmingham, Alabama. The case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA case could have a significant adverse impact on the Company, it is party to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. However, an adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. This could affect future results of operations, cash flows, and possibly financial condition unless such costs can be recovered through regulated rates. In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury, and perhaps other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act, and the regulations are scheduled to be finalized by the end of 2004 with implementation to take place around 2007. In January 2001, the EPA proposed guidance for the determination of Best Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls is expected to take place around 2010. Litigation of the Regional II-55 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report Haze Regulations, including the BART provisions, is ongoing in the Federal District of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002. Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide and reductions in mercury and other HAPS emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. In October 1997, the EPA issued regulations setting forth requirements for Compliance Assurance Monitoring (CAM) in its state and federal operating permit programs. These regulations were amended by the EPA in March 2001 in response to a court order resolving challenges to the rules brought by environmental groups and industry. Generally, this rule affects the operation and maintenance of electrostatic precipitators and could involve significant additional ongoing expense. The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and will recognize in the financial statements costs to clean up known sites. The Company has not incurred any significant cleanup costs to date. Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, and other environmental and health concerns could significantly affect the Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. 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 internal sources. However, the type and timing of any financings - if needed - will depend on market conditions and regulatory approval. In recent years financings primarily have utilized unsecured debt and trust preferred securities. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company operating companies. At December 31, 2001, the Company had outstanding $10 million of commercial paper. As required by the Nuclear Regulatory Commission and as ordered by the APSC, the Company has established external trust funds for nuclear decommissioning costs. In 1994 the Company also established an external trust fund for postretirement benefits as ordered by the APSC. The cumulative effect of funding these items over a long period will diminish internally funded capital and may require capital from other sources. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning." Cautionary Statement Regarding Forward-Looking Information This Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning projected retail sales growth and scheduled completion of new generation. In some cases forward-looking statements can be identified by terminology such as "may," "will," "should," "could," "expects," "plans," II-56 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2001 Annual Report "anticipates," "believes," "estimates," "predicts," "projects," "potential," "continue," or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental 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, including the pending EPA civil action against the Company; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; 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 effects of and changes in economic conditions in the areas in which the Company operates; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and acceptance of the Company's new product and service offerings; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission. II-57
STATEMENTS OF INCOME For the Years Ended December 31, 2001, 2000, and 1999 Alabama Power Company 2001 Annual Report --------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Revenues: Retail sales $2,747,673 $2,952,707 $2,811,117 Sales for resale -- Non-affiliates 485,974 461,730 415,377 Affiliates 245,189 166,219 92,439 Other revenues 107,554 86,805 66,541 --------------------------------------------------------------------------------------------------------------------- Total operating revenues 3,586,390 3,667,461 3,385,474 --------------------------------------------------------------------------------------------------------------------- Operating Expenses: Operation -- Fuel 1,000,828 963,275 855,632 Purchased power -- Non-affiliates 144,991 164,881 93,204 Affiliates 147,967 184,014 180,563 Other 508,264 538,529 531,696 Maintenance 275,510 301,046 277,724 Depreciation and amortization 383,473 364,618 347,574 Taxes other than income taxes 214,665 209,673 204,645 --------------------------------------------------------------------------------------------------------------------- Total operating expenses 2,675,698 2,726,036 2,491,038 --------------------------------------------------------------------------------------------------------------------- Operating Income 910,692 941,425 894,436 Other Income (Expense): Interest income, net 15,101 16,152 15,671 Equity in earnings of unconsolidated subsidiaries (Note 5) 4,494 3,156 2,650 Other, net (8,579) (2,226) (12,805) --------------------------------------------------------------------------------------------------------------------- Earnings Before Interest and Income Taxes 921,708 958,507 899,952 --------------------------------------------------------------------------------------------------------------------- Interest and Other: Interest expense, net 246,436 235,331 217,066 Distributions on preferred securities of subsidiary (Note 8) 24,775 25,549 24,662 --------------------------------------------------------------------------------------------------------------------- Total interest and other, net 271,211 260,880 241,728 --------------------------------------------------------------------------------------------------------------------- Earnings Before Income Taxes 650,497 697,627 658,224 Income taxes (Note 7) 248,597 261,555 241,880 --------------------------------------------------------------------------------------------------------------------- Earnings Before Cumulative Effect of 401,900 436,072 416,344 Accounting Change Cumulative effect of accounting change less income taxes of $215 thousand 353 - - --------------------------------------------------------------------------------------------------------------------- Net Income 402,253 436,072 416,344 Dividends on Preferred Stock 15,524 16,156 16,464 --------------------------------------------------------------------------------------------------------------------- Net Income After Dividends on Preferred Stock $ 386,729 $ 419,916 $ 399,880 ===================================================================================================================== The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001, 2000, and 1999 Alabama Power Company 2001 Annual Report ---------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Activities: Net income $ 402,253 $ 436,072 $ 416,344 Adjustments to reconcile net income to net cash provided from operating activities -- Depreciation and amortization 437,490 412,998 403,332 Deferred income taxes and investment tax credits, net (21,569) 66,166 29,039 Other, net (122,651) (37,703) (12,661) Changes in certain current assets and liabilities -- Receivables, net 88,325 (125,652) 33,509 Fossil fuel stock (38,663) 23,967 (1,344) Materials and supplies (13,025) (10,662) (17,968) Accounts payable (83,077) 107,702 (38,556) Energy cost recovery, retail 154,320 (69,190) (97,869) Other 34,503 23,336 5,930 ---------------------------------------------------------------------------------------------------------------------------- Net cash provided from operating activities 837,906 827,034 719,756 ---------------------------------------------------------------------------------------------------------------------------- Investing Activities: Gross property additions (635,540) (870,581) (809,044) Sales of property 102,068 - - Other (34,771) (49,414) (72,218) ---------------------------------------------------------------------------------------------------------------------------- Net cash used for investing activities (568,243) (919,995) (881,262) ---------------------------------------------------------------------------------------------------------------------------- Financing Activities: Increase (decrease) in notes payable, net (271,347) 184,519 96,824 Proceeds -- Common stock 15,642 - - Other long-term debt 477,000 250,000 751,650 Preferred securities - - 50,000 Capital contributions from parent company 107,313 204,371 204,347 Redemptions -- First mortgage bonds (138,991) (111,009) (470,000) Other long-term debt (19,021) (5,987) (104,836) Preferred stock - - (50,000) Payment of preferred stock dividends (14,942) (16,110) (15,788) Payment of common stock dividends (393,900) (417,100) (399,600) Other (9,908) (951) (15,864) ---------------------------------------------------------------------------------------------------------------------------- Net cash provided from (used for) financing activities (248,154) 87,733 46,733 ---------------------------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents 21,509 (5,228) (114,773) Cash and Cash Equivalents at Beginning of Period 14,247 19,475 134,248 ---------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 35,756 $ 14,247 $ 19,475 ============================================================================================================================ Supplemental Cash Flow Information: Cash paid during the period for -- Interest (net of amount capitalized) $246,316 $237,066 $229,305 Income taxes (net of refunds) 223,961 175,303 170,121 ------------------------------------------------------------------------------------------------------------------------------------ The accompanying notes are an integral part of these statements.
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BALANCE SHEETS At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------- Assets 2001 2000 ------------------------------------------------------------------------------------------------------------------- (in thousands) Current Assets: Cash and cash equivalents $ 35,756 $ 14,247 Receivables -- Customer accounts receivable 281,985 337,870 Under-recovered retail fuel clause revenue 83,497 237,817 Other accounts and notes receivable 49,940 60,315 Affiliated companies 72,639 95,704 Accumulated provision for uncollectible accounts (5,237) (6,237) Refundable income taxes - - Fossil fuel stock, at average cost 99,278 60,615 Materials and supplies, at average cost 191,324 178,299 Other 74,640 52,624 ------------------------------------------------------------------------------------------------------------------- Total current assets 883,822 1,031,254 ------------------------------------------------------------------------------------------------------------------- Property, Plant, and Equipment: In service 13,159,560 12,431,575 Less accumulated provision for depreciation 5,309,557 5,107,822 ------------------------------------------------------------------------------------------------------------------- 7,850,003 7,323,753 Nuclear fuel, at amortized cost 88,777 94,050 Construction work in progress 357,906 744,974 ------------------------------------------------------------------------------------------------------------------- Total property, plant, and equipment 8,296,686 8,162,777 ------------------------------------------------------------------------------------------------------------------- Other Property and Investments: Equity investments in unconsolidated subsidiaries (Note 5) 44,742 38,623 Nuclear decommissioning trusts 317,508 313,895 Other 12,244 13,612 ------------------------------------------------------------------------------------------------------------------- Total other property and investments 374,494 366,130 ------------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets: Deferred charges related to income taxes (Note 7) 334,830 345,550 Prepaid pension costs 314,100 255,256 Debt expense, being amortized 8,150 8,758 Premium on reacquired debt, being amortized 77,173 76,020 Department of Energy assessments 21,015 24,588 Other 108,031 95,772 ------------------------------------------------------------------------------------------------------------------- Total deferred charges and other assets 863,299 805,944 ------------------------------------------------------------------------------------------------------------------- Total Assets $10,418,301 $10,366,105 =================================================================================================================== The accompanying notes are an integral part of these balance sheets.
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BALANCE SHEETS At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------------------- Liabilities and Stockholder's Equity 2001 2000 -------------------------------------------------------------------------------------------------------------------------- (in thousands) Current Liabilities: Securities due within one year (Note 8) $ 5,382 $ 844 Notes payable 9,996 281,343 Accounts payable -- Affiliated 98,268 124,534 Other 151,705 209,205 Customer deposits 42,124 36,814 Taxes accrued -- Income taxes 113,003 65,505 Other 19,023 19,471 Interest accrued 35,522 33,186 Vacation pay accrued 32,324 31,711 Other 93,589 97,743 -------------------------------------------------------------------------------------------------------------------------- Total current liabilities 600,936 900,356 -------------------------------------------------------------------------------------------------------------------------- Long-term debt (See accompanying statements) 3,742,346 3,425,527 -------------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes (Note 7) 1,387,661 1,401,424 Deferred credits related to income taxes (Note 7) 202,881 222,485 Accumulated deferred investment tax credits 238,225 249,280 Employee benefits provisions 99,919 71,813 Prepaid capacity revenues (Note 6) 40,730 58,377 Other 130,214 176,559 -------------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 2,099,630 2,179,938 -------------------------------------------------------------------------------------------------------------------------- Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding company junior subordinated notes (See accompanying statements) (Note 8) 347,000 347,000 -------------------------------------------------------------------------------------------------------------------------- Cumulative preferred stock (See accompanying statements) 317,512 317,512 -------------------------------------------------------------------------------------------------------------------------- Common stockholder's equity (See accompanying statements) 3,310,877 3,195,772 -------------------------------------------------------------------------------------------------------------------------- Total Liabilities and Stockholder's Equity $10,418,301 $10,366,105 ========================================================================================================================== The accompanying notes are an integral part of these balance sheets.
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STATEMENTS OF CAPITALIZATION At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report ---------------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ---------------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Long-Term Debt: First mortgage bonds -- Maturity Interest Rates -------- -------------- 2023 through 2024 7.30% - 7.75% $350,000 $488,991 ---------------------------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 350,000 488,991 ---------------------------------------------------------------------------------------------------------------------------------- Senior notes -- Variable rate (2.28% at 1/1/02) due March 3, 2003 167,000 - 5.35% due November 15, 2003 156,200 156,200 7.850% due May 15, 2003 250,000 250,000 7.125% due August 15, 2004 250,000 250,000 4.875% due September 1, 2004 275,000 - 5.49% due November 1, 2005 225,000 225,000 7.125% due October 1, 2007 200,000 200,000 5.375% due October 1, 2008 160,000 160,000 6.25% to 7.125% due 2010-2048 1,199,402 1,202,581 ---------------------------------------------------------------------------------------------------------------------------------- Total senior notes 2,882,602 2,443,781 ---------------------------------------------------------------------------------------------------------------------------------- Other long-term debt -- Pollution control revenue bonds -- Collateralized: 5.50% due 2024 24,400 24,400 Variable rates (1.61% to 1.95% at 1/1/02) due 2015-2017 89,800 89,800 Non-collateralized: 6.69% due 2021 50,000 65,000 Variable rates (1.75% to 2.05% at 1/1/02) due 2021-2031 395,940 360,940 ---------------------------------------------------------------------------------------------------------------------------------- Total other long-term debt (Note 8) 560,140 540,140 ---------------------------------------------------------------------------------------------------------------------------------- Capitalized lease obligations 3,323 4,165 ---------------------------------------------------------------------------------------------------------------------------------- Unamortized debt premium (discount), net (48,337) (50,706) ---------------------------------------------------------------------------------------------------------------------------------- Total long-term debt (annual interest requirement -- $217.2 million) 3,747,728 3,426,371 Less amount due within one year 5,382 844 ---------------------------------------------------------------------------------------------------------------------------------- Long-term debt excluding amount due within one year $3,742,346 $3,425,527 48.5% 46.9% ----------------------------------------------------------------------------------------------------------------------------------
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STATEMENTS OF CAPITALIZATION (continued) At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 -------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Company Obligated Mandatorily Redeemable Preferred Securities: (Note 8) $25 liquidation value -- 7.375% $ 97,000 $ 97,000 7.60% 200,000 200,000 Auction rate (3.60% at 1/1/02) 50,000 50,000 -------------------------------------------------------------------------------------------------------------------------- Total (annual distribution requirement -- $24.2 million) 347,000 347,000 4.5 4.8 -------------------------------------------------------------------------------------------------------------------------- Cumulative Preferred Stock: $100 par or stated value -- 4.20% to 4.92% 47,512 47,512 $25 par or stated value -- 5.20% to 5.83% 200,000 200,000 Auction rates -- at 1/1/02 3.10% to 3.557% 70,000 70,000 -------------------------------------------------------------------------------------------------------------------------- Total (annual dividend requirement -- $15.2 million) 317,512 317,512 4.1 4.4 -------------------------------------------------------------------------------------------------------------------------- Common Stockholder's Equity: Common stock, par value $40 per share -- Authorized - 6,000,000 shares Outstanding - 6,000,000 shares in 2001 and 5,608,955 shares in 2000 Par value 240,000 224,358 Paid-in capital 1,850,676 1,743,363 Premium on Preferred Stock 99 99 Retained earnings 1,220,102 1,227,952 -------------------------------------------------------------------------------------------------------------------------- Total common stockholder's equity 3,310,877 3,195,772 42.9 43.9 -------------------------------------------------------------------------------------------------------------------------- Total Capitalization $7,717,735 $7,285,811 100.0% 100.0% ========================================================================================================================== The accompanying notes are an integral part of these statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2001, 2000, and 1999 Alabama Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------- Premium on Common Paid-In Preferred Retained Stock Capital Stock Earnings Total ----------------------------------------------------------------------------------------------------------------------------- (in thousands) Balance at January 1, 1999 $224,358 $1,334,645 $99 $1,224,965 $2,784,067 Net income after dividends on preferred stock - - - 399,880 399,880 Capital contributions from parent company - 204,347 - - 204,347 Cash dividends on common stock - - - (399,600) (399,600) Other - - - 169 169 ----------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 224,358 1,538,992 99 1,225,414 2,988,863 Net income after dividends on preferred stock - - - 419,916 419,916 Capital contributions from parent company - 204,371 - - 204,371 Cash dividends on common stock - - - (417,100) (417,100) Other - - - (278) (278) ----------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 224,358 1,743,363 99 1,227,952 3,195,772 Net income after dividends on preferred stock - - - 386,729 386,729 Capital contributions from parent company - 107,313 - - 107,313 Cash dividends on common stock - - - (393,900) (393,900) Issuance of common stock 15,642 - - - 15,642 Other - - - (679) (679) ---------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 $240,000 $1,850,676 $99 $1,220,102 $3,310,877 ============================================================================================================================= The accompanying notes are an integral part of these statements.
II-64 NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2001 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern LINC), Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern Power), and other direct and indirect subsidiaries. The operating companies -- Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four southeastern states. Contracts among the operating companies - related to jointly-owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). The system service company provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Alabama Public Service Commission (APSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its respective 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. Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation. Affiliate Transactions The Company has an agreement with the system service company under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $183 million, $187 million, and $218 million during 2001, 2000, and 1999, respectively. The Company also has an agreement with Southern Nuclear to operate Plant Farley and provide the following nuclear-related services at cost: general executive and advisory services; general operations, management and technical services; administrative services including procurement, accounting, statistical, and employee relations; and other services with respect to business and operations. Costs for these services amounted to $160 million, $148 million, and $135 million during 2001, 2000, and 1999, respectively. In 2001, the Company had under construction a 1,230 megawatt combined cycle facility in Autaugaville, Alabama. In June 2001, the Company sold this project to Southern Power Company, a new Southern Company affiliate formed in 2001 to construct, own, and manage wholesale generating assets in the Southeast. Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. II-65 NOTES (continued) Alabama Power Company 2001 Annual Report Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following: 2001 2000 ----------------------- (in millions) Deferred income tax charges $ 335 $ 346 Deferred income tax credits (203) (222) Premium on reacquired debt 77 76 Department of Energy assessments 21 25 Vacation pay 32 32 Natural disaster reserve (12) (18) Other, net 57 30 ---------------------------------------------------------------- Total $ 307 $ 269 ================================================================ In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair values. Revenues and Fuel Costs The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Alabama and to wholesale customers in the southeast. Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel revenues have no effect on net income because they represent the recording of revenues to offset fuel expenses, including the fuel component of purchased energy. Fuel rates billed to customers are designed to fully recover fluctuating fuel costs over a period of time. The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continue to average less than 1 percent of revenues. Fuel expense includes the amortization of the cost of nuclear fuel and a charge based on nuclear generation for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $58 million in 2001, $61 million in 2000, and $63 million in 1999. The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in January 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient fuel storage capacity is available at Plant Farley to maintain full-core discharge capability until the refueling outage scheduled in 2006 for Farley Unit 1 and the refueling outage scheduled in 2008 for Farley Unit 2. Procurement of on-site dry spent fuel storage capacity at Plant Farley is in progress, with the intent to place the capacity in operation as early as 2005. Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company estimates its remaining liability under this law to be approximately $21 million at December 31, 2001. This obligation is recognized in the accompanying Balance Sheets. Depreciation and Nuclear Decommissioning Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2 percent in 2001, 2000, and 1999. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -- together with the cost of removal, less salvage -- is charged to accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of decommissioning nuclear facilities and removal of other facilities. The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial nuclear power reactors to establish a plan for providing with reasonable assurance funds for decommissioning. The Company has established external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the APSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. II-66 NOTES (continued) Alabama Power Company 2001 Annual Report The Company has filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. Site study cost is the estimate to decommission the facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs - based on the most current study for Plant Farley were as follows: Site study basis (year) 1998 Decommissioning periods: Beginning year 2017 Completion year 2031 ------------------------------------------------------------ (in millions) Site study costs: Radiated structures $629 Non-radiated structures 60 ------------------------------------------------------------ Total $689 ============================================================ (in millions) Ultimate costs: Radiated structures $1,868 Non-radiated structures 178 ------------------------------------------------------------ Total $2,046 ============================================================ The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making estimates. Annual provisions for nuclear decommissioning are based on an annuity method as approved by the APSC. The amount expensed in 2001 and fund balances as of December 31, 2001 were: (in millions) Amount expensed in 2001 $ 18 ------------------------------------------------------------- Accumulated provisions: External trust funds, at fair value $318 Internal reserves 36 ------------------------------------------------------------- Total $354 ============================================================= All of the Company's decommissioning costs are approved for recovery by the APSC through the ratemaking process. Significant assumptions include an estimated inflation rate of 4.5 percent and an estimated trust earnings rate of 7.0 percent. The Company expects the APSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning. Income Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property. Allowance For Funds Used During Construction (AFUDC) AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The amount of AFUDC capitalized was $19 million in 2001, $43 million in 2000, and $23 million in 1999. The composite rate used to determine the amount of allowance was 7.7 percent in 2001, 9.6 percent in 2000, and 8.8 percent in 1999. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 3.3 percent in 2001, 8.4 percent in 2000, and 4.7 percent in 1999. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property--exclusive of minor items of property--is capitalized. Financial Instruments Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The impact on net income was immaterial. The Company uses derivative financial instruments to hedge exposures to fluctuations in foreign currency exchange rates and certain commodity prices. II-67 NOTES (continued) Alabama Power Company 2001 Annual Report Gains and losses on qualifying hedges are deferred and recognized either in income or as an adjustment to the carrying amount of the hedged item when the transaction occurs. The Company and its affiliates, through the system service company acting as their agent, enters into commodity related forward and option contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of the Company's bulk energy purchases and sales contracts meet the definition of a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. In many cases these fuel and electricity contracts qualify for normal purchase and sale exceptions under Statement No. 133 and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income. In October 2001, the APSC approved a revision to the Company's Rate ECR (Energy Cost Recovery) allowing the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at its electric generating facilities. This revision also includes the cost of financial tools used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. 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. Other Company financial instruments for which the carrying amount did not equal fair value at December 31 are as follows: Carrying Fair Amount Value ------------------------- (in millions) Long-term debt: At December 31, 2001 $3,744 $3,800 At December 31, 2000 3,422 3,375 Preferred Securities: At December 31, 2001 347 346 At December 31, 2000 347 344 -------------------------------------------------------------- The fair value for long-term debt and preferred securities was based on either closing market prices or closing prices of comparable instruments. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Natural Disaster Reserve In accordance with an APSC order, the Company has established a Natural Disaster Reserve. The Company is allowed to accrue $250 thousand per month until the maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. At December 31, 2001, the reserve balance was $12 million. 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan that covers substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for such benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations or to the extent required by the APSC and the FERC. In late 2000 the Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees. II-68 NOTES (continued) Alabama Power Company 2001 Annual Report The measurement date for plan assets and obligations is September 30 of each year. The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were: 2001 2000 ------------------------------------------------------------- Discount 7.50% 7.50% Annual salary increase 5.00 5.00 Long-term return on plan assets 8.50 8.50 ------------------------------------------------------------- Pension Plan Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations ------------------------ 2001 2000 ------------------------------------------------------------ (in millions) Balance at beginning of year $925 $896 Service cost 25 23 Interest cost 70 65 Benefits paid (56) (51) Actuarial gain and employee transfers (1) (8) Amendments 48 - ------------------------------------------------------------ Balance at end of year $1,011 $925 ============================================================ Plan Assets ------------------------ 2001 2000 ------------------------------------------------------------ (in millions) Balance at beginning of year $1,921 $1,647 Actual return on plan assets (277) 302 Benefits paid (56) (51) Employee transfers (4) 23 ------------------------------------------------------------ Balance at end of year $1,584 $1,921 ============================================================ The accrued pension costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------- (in millions) Funded status $ 573 $ 996 Unrecognized transition obligation (15) (20) Unrecognized prior service cost 78 36 Unrecognized net actuarial gain (322) (757) --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 314 $ 255 =============================================================== Components of the pension plan's net periodic cost were as follows: 2001 2000 1999 --------------------------------------------------------------- (in millions) Service cost $ 25 $ 23 $ 23 Interest cost 70 65 58 Expected return on plan assets (131) (119) (109) Recognized net actuarial gain (22) (19) (13) Net amortization 1 (1) (1) --------------------------------------------------------------- Net pension income $ (57) $ (51) $ (42) =============================================================== Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations ------------------------- 2001 2000 ------------------------------------------------------------- (in millions) Balance at beginning of year $264 $264 Service cost 5 4 Interest cost 24 19 Benefits paid (18) (12) Actuarial gain and employee transfers (13) (11) Amendments 86 - ------------------------------------------------------------- Balance at end of year $348 $264 ============================================================= Plan Assets ------------------------- 2001 2000 ------------------------------------------------------------- (in millions) Balance at beginning of year $192 $161 Actual return on plan assets (24) 25 Employer contributions 19 18 Benefits paid (18) (12) ------------------------------------------------------------- Balance at end of year $169 $192 ============================================================= The accrued postretirement costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------- (in millions) Funded status $ (179) $ (72) Unrecognized transition obligation 45 49 Prior service cost 82 - Unrecognized net actuarial gain (9) (35) Fourth quarter contributions 8 4 --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (53) $ (54) =============================================================== II-69 NOTES (continued) Alabama Power Company 2001 Annual Report Components of the plans' net periodic cost were as follows: 2001 2000 1999 --------------------------------------------------------------- (in millions) Service cost $ 5 $ 4 $ 5 Interest cost 24 19 18 Expected return on plan assets (15) (13) (11) Net amortization 7 4 4 --------------------------------------------------------------- Net postretirement cost $ 21 $ 14 $ 16 =============================================================== An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 9.25 percent for 2001, decreasing gradually to 5.25 percent through the year 2010, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2001 as follows: 1 Percent 1 Percent Increase Decrease --------------------------------------------------------------- (in millions) Benefit obligation $30 $26 Service and interest costs 3 2 =============================================================== Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2001, 2000, and 1999 were $12 million, $11 million, and $10 million, respectively. Work Force Reduction Programs The Company has incurred costs for work force reduction programs totaling $13.0 million, $2.6 million and $5.6 million for the years 2001, 2000 and 1999, respectively. These costs were deferred and are being amortized in accordance with regulatory treatment. The unamortized balance of these costs was $11.9 million at December 31, 2001. 3. CONTINGENCIES AND REGULATORY MATTERS General The Company is subject to certain claims and legal actions arising in the ordinary course of business. In the opinion of management after consultation with legal counsel, the ultimate disposition of these matters is not expected to have a material adverse effect on the Company's financial condition. Environmental Litigation On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in U.S. District Court in Georgia against the Company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. On August 1, 2000, the U.S. District Court granted the Company's motion to dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims against the Company in federal district court in Birmingham, Alabama. The Company's case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA case could have II-70 NOTES (continued) Alabama Power Company 2001 Annual Report a significant adverse impact on the Company, it is a party to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. Retail Rate Adjustment Procedures The APSC has adopted rates that provide for periodic adjustments based upon the Company's earned return on end-of-period retail common equity. The rates also provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP (Certificated New Plant). Both increases and decreases have been placed into effect since the adoption of these rates. Effective July 2001, the Company's retail rates were adjusted by 0.6 percent under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into commercial operation on May 1, 2001. Most recently, a 2 percent increase in retail rates was effective in October 2001 in accordance with the Rate Stabilization Equalization plan. The rate adjustment procedures allow a return on common equity range of 13.0 percent to 14.5 percent and limit increases or decreases in rates to 4 percent in any calendar year. In December 1995, the APSC issued an order authorizing the Company to reduce balance sheet items -- such as plant and deferred charges -- at any time the Company's actual base rate revenues exceed the budgeted revenues. During the years 2001, 2000, and 1999, the Company did not record any such reductions. In April 2000, the APSC approved an amendment to the Company's existing rate structure to provide for the recovery of retail costs associated with certified purchased power agreements. In November 2000, the APSC certified a seven-year purchased power agreement pertaining to 615 megawatts of the wholesale generating facilities which were sold to Southern Power in June 2001 and are under construction in Autaugaville, Alabama. All of the 615 megawatts will be delivered beginning in 2003. In addition the APSC certified a seven-year purchased power agreement with a third party for approximately 630 megawatts; one half of the power will be delivered beginning in 2003 while the remaining half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail rates when the contracted capacity delivery begins. In October 2001, the APSC approved a revision to the Company's Rate ECR (Energy Cost Recovery) allowing the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at its electric generating facilities. This revision also includes the cost of financial tools used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. The Company's ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them. 4. COMMITMENTS Construction Program During 2001, the Company completed the replacement of the steam generators at Plant Farley, as well as the construction of new generating capacity at Plant Barry. Significant construction will continue related to transmission and distribution facilities and the upgrading of generating plants, including the expenditures necessary to comply with environmental regulation. The Company currently estimates property additions to be $671 million in 2002, $592 million in 2003, and $673 million in 2004. In connection with the transfer of the Autaugaville construction project, the Company has assigned $71 million in vendor equipment contracts to Southern Power. While the Company could be obligated to assume responsibility for these contracts if Southern Power fails to meet these commitments, Southern Company has entered into limited keep-well arrangements whereby Southern Company would contribute funds to Southern Power either through loans or capital contributions in order to fund performance by Southern Power as equipment purchaser under certain contingencies. Southern Company has also guaranteed Southern Power obligations totaling $6.6 million for the Company's construction of transmission interconnection facilities to the plant. The capital budget is subject to periodic review and revision, and actual capital costs incurred may vary from estimates because of changes in such II-71 NOTES (continued) Alabama Power Company 2001 Annual Report factors as: business conditions; environmental regulations; nuclear plant regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition there can be no assurance that costs related to capital expenditures will be fully recovered. Purchased Power Commitments The Company has entered into various long-term commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2001 were as follows: Commitments ----------------------------------- Non- Year Affiliated Affiliated Total ---- ---------------------------------- (in millions) 2002 $ - $ - $ - 2003 37 16 53 2004 49 34 83 2005 49 37 86 2006 49 38 87 2007 and thereafter 160 142 302 -------------------------------------------------------------- Total commitments $344 $267 $611 ============================================================== Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Total estimated long-term obligations at December 31, 2001, were as follows: Year Commitments ---- --------------- (in millions) 2002 $ 795 2003 794 2004 801 2005 571 2006 512 2007 and thereafter 1,020 --------------------------------------------------------------- Total commitments $4,493 =============================================================== In addition, the system service company acts as agent for the five operating companies and Southern Power with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes allocated based on usage projections, as of December 31, 2001, are as follows: Year Natural Gas ---- ----------- (MMBtu) 2002 77,365,361 2003 72,139,927 2004 45,600,417 2005 22,849,132 2006 14,808,334 2007 and thereafter 5,609,190 ------------------------------------------------------------ Total commitments 238,372,361 ============================================================ Additional commitments for fuel will be required in the future to supply the Company's fuel needs. Operating Leases The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses totaled $27.9 million in 2001, $20.9 million in 2000, and $17.8 million in 1999. At December 31, 2001, estimated minimum rental commitments for noncancellable operating leases were as follows: Year Commitments ---- ---------------- (in millions) 2002 $ 27.9 2003 26.5 2004 25.5 2005 21.6 2006 14.4 2007 and thereafter 38.1 -------------------------------------------------------------- Total minimum payments $ 154.0 ============================================================== In addition to the rental commitments above, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2004 and 2006, and the Company's maximum obligations are $25.7 million and $66.0 million, respectively. At the termination of the leases, at the Company's option, the Company may negotiate an extension, 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. 5. JOINT OWNERSHIP AGREEMENTS The Company and Georgia Power own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which owns electric generating units with a total rated capacity of 1,020 megawatts, together with associated II-72 NOTES (continued) Alabama Power Company 2001 Annual Report transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party's right to cancel upon two year's notice. The Company's share of expenses totaled $80 million in 2001, $85 million in 2000, and $92 million in 1999 and is included in "Purchased power from affiliates" in the Statements of Income. In addition the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligation corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty. At December 31, 2001, the capitalization of SEGCO consisted of $58 million of equity and $86 million of long-term debt on which the annual interest requirement is $2.2 million. SEGCO paid dividends totaling $0.7 million in 2001, $5.1 million in 2000, and $4.3 million in 1999 of which one-half of each was paid to the Company. SEGCO's net income was $7.5 million, $5.9 million, and $5.4 million for 2001, 2000, and 1999, respectively. The Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2001, is as follows: Total Megawatt Company Facility (Type) Capacity Ownership --------------------- ------------ ------------- Greene County 500 60.00% (1) (coal) Plant Miller Units 1 and 2 1,320 91.84% (2) (coal) ----------------------------------------------------------- (1) Jointly owned with an affiliate, Mississippi Power Company. (2) Jointly owned with Alabama Electric Cooperative, Inc. Company Accumulated Facility Investment Depreciation --------------------- -------------- --------------- (in millions) Greene County $101 $ 49 Plant Miller Units 1 and 2 747 326 ---------------------------------------------------------- 6. LONG-TERM POWER SALES AGREEMENTS General The Company and the other operating companies of Southern Company have entered into long-term contractual agreements for the sale and lease of capacity and energy to certain non-affiliated utilities located outside the system's service area. These agreements -- expiring at various dates discussed below -- are firm and related to specific generating units. Because the energy is generally provided at cost under these agreements, profitability is primarily affected by capacity revenues. Unit power from Plant Miller is being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority (JEA). Under these agreements approximately 1,237 megawatts of capacity are scheduled to be sold through 2010. The Company's capacity revenues amounted to $125 million in 2001, $127 million in 2000, and $122 million in 1999. Alabama Municipal Electric Authority (AMEA) Capacity Contracts In 1986 the Company entered into a firm power sales contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for a period of 15 years (1986 Contract). In October 1991 the Company entered into a second firm power sales contract with AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80 megawatts) for a period of 15 years (1991 Contract). Under the terms of the contracts, the Company received payments from AMEA representing the net present value of the revenues associated with the respective capacity entitlements, discounted at effective annual rates of 9.96 percent and 11.19 percent for the 1986 and 1991 contracts, respectively. The 1986 contract expired in July 2001, however, the payments for the 1991 contract will continue to be recognized as operating revenues and the discounts will be amortized to other interest expense as scheduled capacity is made available over the terms of the contract. To secure AMEA's advance payments and the Company's performance obligation under the contracts, the Company issued and delivered to an escrow agent first mortgage bonds representing the maximum amount of liquidated damages payable by the Company in the event of a default under the contracts. No principal or interest is payable on such bonds unless and until a default by the Company II-73 NOTES (continued) Alabama Power Company 2001 Annual Report occurs. As the liquidated damages decline, a portion of the bond equal to the decrease is returned to the Company. At December 31, 2001, $38.1 million of the 1991 bond was held by the escrow agent under the contract. 7. INCOME TAXES At December 31, 2001, the tax-related regulatory assets and liabilities were $335 million and $203 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Details of the income tax provisions are as follows: 2001 2000 1999 -------------------------------- (in millions) Total provision for income taxes: Federal -- Current $234 $168 $194 Deferred (20) 60 24 ----------------------------------------------------------------- 214 228 218 ----------------------------------------------------------------- State -- Current 37 27 19 Deferred (2) 7 5 ----------------------------------------------------------------- 35 34 24 ----------------------------------------------------------------- Total $249 $262 $242 ================================================================= 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: 2001 2000 ------------------ (in millions) Deferred tax liabilities: Accelerated depreciation $ 1,034 $ 992 Property basis differences 390 405 Fuel cost adjustment 28 93 Premium on reacquired debt 29 30 Pensions 89 75 Other 23 12 ----------------------------------------------------------------- Total 1,593 1,607 ----------------------------------------------------------------- Deferred tax assets: Capacity prepayments 13 18 Other deferred costs 14 14 Postretirement benefits 21 24 Unbilled revenue 18 23 Other 93 81 ----------------------------------------------------------------- Total 159 160 ----------------------------------------------------------------- Total deferred tax liabilities, net 1,434 1,447 Portion included in current liabilities, net (47) (46) ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,387 $1,401 ================================================================= Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $11 million in 2001, 2000, and 1999. At December 31, 2001, all investment tax credits available to reduce federal income taxes payable had been utilized. A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2001 2000 1999 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.5 3.1 2.4 Non-deductible book depreciation 1.5 1.4 1.6 Differences in prior years' deferred and current tax rates (1.3) (1.3) (1.3) Other (0.5) (0.7) (0.9) --------------------------------------------------------------- Effective income tax rate 38.2% 37.5% 36.8% =============================================================== Southern Company files a consolidated federal and certain state income tax returns. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability. II-74 NOTES (continued) Alabama Power Company 2001 Annual Report 8. CAPITALIZATION Mandatorily Redeemable Preferred Securities Statutory business trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities as follows: Date of Maturity Issue Amount Rate Notes Date --------------------------------------------------- (millions) (millions) Trust I 1/1996 $ 97 7.375% $100 3/2026 Trust II 1/1997 200 7.60 206 12/2036 Trust III 2/1999 50 Auction 52 2/2029 Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above. The distribution rate of Trust III's auction rate securities was 3.60% at January 1, 2002. The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with respect to the preferred securities. The Trusts are subsidiaries of the Company and accordingly are consolidated in the Company's financial statements. Pollution Control Bonds Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $114.2 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements. In 2001, the Company sold, through a public authority, $20 million of pollution control bonds, the proceeds of which were used to pay certain costs incurred in connection with the acquisition, construction, installation, and equipping of certain local district heating facilities and sewage and solid waste facilities at two of the Company's generation facilities. Senior Notes In August 2001 the Company issued $442 million of unsecured senior notes, the proceeds of which were used to redeem the $131.5 million outstanding principal of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other corporate purposes including the repayment of a portion of its short-term indebtedness. All of the Company's senior notes are, in effect, subordinate to all secured debt of the Company, including its first mortgage bonds. Capitalized Leases The estimated aggregate annual maturities of capitalized lease obligations through 2006 are as follows: $0.9 million in 2002, $0.9 million in 2003, $1.0 million in 2004, $0.4 million in 2005, and $0.1 million in 2006. Securities Due Within One Year A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows: 2001 2000 ---------------------- (in thousands) First mortgage bond maturities and redemptions $4,498 $ - Other long-term debt maturities 884 844 ------------------------------------------------------------ Total long-term debt due within one year $5,382 $844 ============================================================ The annual first mortgage bond improvement fund requirement is 1 percent of the aggregate principal amount of bonds of each series authenticated, so long as a portion of that series is outstanding, and may be satisfied by the deposit of cash and/or reacquired bonds, the certification of unfunded property additions, or a combination thereof. Bank Credit Arrangements The Company maintains committed lines of credit in the amount of $964 million (including $454 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds). Of these lines, $574 million expire at various times during 2002 and $390 million expire in II-75 NOTES (continued) Alabama Power Company 2001 Annual Report 2004. In certain cases, such lines require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Because the arrangements are based on an average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. Moreover, the Company borrows from time to time pursuant to arrangements with banks for uncommitted lines of credit. The amount of commercial paper outstanding at December 31, 2001 was $10 million. At December 31, 2001, the Company had regulatory approval to have outstanding up to $1 billion of short-term borrowings. Assets Subject to Lien The Company's mortgage, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company's fixed property and franchises. Dividend Restrictions The Company's first mortgage bond indenture contains various common stock dividend restrictions that remain in effect as long as the bonds are outstanding. At December 31, 2001, retained earnings of $796 million were restricted against the payment of cash dividends on common stock under terms of the mortgage indenture. 9. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act of 1988 (the Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $9.5 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $200 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums which could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $88 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $176 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year. The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities. Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional cost that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the three NEIL policies would be $35 million. Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power stations would be covered under their insurance. However, both companies revised their policy terms on a prospective basis to include an industry aggregate for all terrorist acts. The NEIL aggregate, which applies to all claims stemming from terrorism within a 12 month duration, is $3.24 billion plus any amounts that would be available through reinsurance or indemnity from an outside source. The ANI cap is $200 million in a policy year. 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. II-76 NOTES (continued) Alabama Power Company 2001 Annual Report 10. QUARTERLY FINANCIAL INFORMATION (Unaudited) Summarized quarterly financial data for 2001 and 2000 are as follows: Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock -------------------- ----------------------------------------- (in millions) March 2001 $ 850 $180 $ 70 June 2001 904 194 75 September 2001 1,061 362 180 December 2001 772 175 62 March 2000 $ 746 $172 $ 68 June 2000 900 229 103 September 2000 1,137 390 209 December 2000 884 151 40 ----------------------------------------------------------------- The Company's business is influenced by seasonal weather conditions. II-77
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 Alabama Power Company 2001 Annual Report ---------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ---------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands) $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111 Net Income after Dividends on Preferred Stock (in thousands) $386,729 $419,916 $399,880 $377,223 $375,939 Cash Dividends on Common Stock (in thousands) $393,900 $417,100 $399,600 $367,100 $339,600 Return on Average Common Equity (percent) 11.89 13.58 13.85 13.63 13.76 Total Assets (in thousands) $10,418,301 $10,366,105 $9,648,704 $9,225,698 $8,812,867 Gross Property Additions (in thousands) $635,540 $870,581 $809,044 $610,132 $451,167 ---------------------------------------------------------------------------------------------------------------------------- Capitalization (in thousands): Common stock equity $3,310,877 $3,195,772 $2,988,863 $2,784,067 $2,750,569 Preferred stock 317,512 317,512 317,512 317,512 255,512 Company obligated mandatorily redeemable preferred securities 347,000 347,000 347,000 297,000 297,000 Long-term debt 3,742,346 3,425,527 3,190,378 2,646,566 2,473,202 ---------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) $7,717,735 $7,285,811 $6,843,753 $6,045,145 $5,776,283 ============================================================================================================================ Capitalization Ratios (percent): Common stock equity 42.9 43.9 43.7 46.1 47.6 Preferred stock 4.1 4.4 4.6 5.3 4.4 Company obligated mandatorily redeemable preferred securities 4.5 4.8 5.1 4.9 5.2 Long-term debt 48.5 46.9 46.6 43.7 42.8 ---------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 ============================================================================================================================ Security Ratings: First Mortgage Bonds - Moody's A1 A1 A1 A1 A1 Standard and Poor's A A A+ A+ A+ Fitch A+ AA- AA- AA- AA- Preferred Stock - Moody's Baa1 a2 a2 a2 a2 Standard and Poor's BBB+ BBB+ A- A A Fitch A- A A A A+ Unsecured Long-Term Debt - Moody's A2 A2 A2 A2 A2 Standard and Poor's A A A A A Fitch A A+ A+ A+ A+ ============================================================================================================================ Customers (year-end): Residential 1,139,542 1,132,410 1,120,574 1,106,217 1,092,161 Commercial 196,617 193,106 188,368 182,738 177,362 Industrial 4,728 4,819 4,897 5,020 5,076 Other 751 745 735 733 728 ---------------------------------------------------------------------------------------------------------------------------- Total 1,341,638 1,331,080 1,314,574 1,294,708 1,275,327 ============================================================================================================================ Employees (year-end): 6,706 6,871 6,792 6,631 6,531 ----------------------------------------------------------------------------------------------------------------------------
II-78
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued) Alabama Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------------ Operating Revenues (in thousands): Residential $ 1,138,499 $1,222,509 $ 1,145,646 $ 1,133,435 $ 997,507 Commercial 829,760 854,695 807,098 779,169 724,148 Industrial 763,934 859,668 843,090 853,550 775,591 Other 15,480 15,835 15,283 14,523 13,563 ------------------------------------------------------------------------------------------------------------------------------ Total retail 2,747,673 2,952,707 2,811,117 2,780,677 2,510,809 Sales for resale - non-affiliates 485,974 461,730 415,377 448,973 431,023 Sales for resale - affiliates 245,189 166,219 92,439 103,562 161,795 ------------------------------------------------------------------------------------------------------------------------------ Total revenues from sales of electricity 3,478,836 3,580,656 3,318,933 3,333,212 3,103,627 Other revenues 107,554 86,805 66,541 53,161 45,484 ------------------------------------------------------------------------------------------------------------------------------ Total $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111 ============================================================================================================================== Kilowatt-Hour Sales (in thousands): Residential 15,880,971 16,771,821 15,699,081 15,794,543 14,336,408 Commercial 12,798,711 12,988,728 12,314,085 11,904,509 11,330,312 Industrial 20,460,022 22,101,407 21,942,889 21,585,117 20,727,912 Other 198,102 205,827 201,149 196,647 180,389 ------------------------------------------------------------------------------------------------------------------------------ Total retail 49,337,806 52,067,783 50,157,204 49,480,816 46,575,021 Sales for resale - non-affiliates 15,277,839 14,847,533 12,437,599 11,840,910 12,329,480 Sales for resale - affiliates 8,843,094 5,369,474 5,031,781 5,976,099 8,993,326 ------------------------------------------------------------------------------------------------------------------------------ Total 73,458,739 72,284,790 67,626,584 67,297,825 67,897,827 ============================================================================================================================== Average Revenue Per Kilowatt-Hour (cents): Residential 7.17 7.29 7.30 7.18 6.96 Commercial 6.48 6.58 6.55 6.55 6.39 Industrial 3.73 3.89 3.84 3.95 3.74 Total retail 5.57 5.67 5.60 5.62 5.39 Sales for resale 3.03 3.11 2.91 3.10 2.78 Total sales 4.74 4.95 4.91 4.95 4.57 Residential Average Annual Kilowatt-Hour Use Per Customer 13,981 14,875 14,097 14,370 13,254 Residential Average Annual Revenue Per Customer $1,002.30 $1,084.26 $1,028.76 $1,031.21 $922.21 Plant Nameplate Capacity Ratings (year-end) (megawatts) 12,153 12,122 11,379 11,151 11,151 Maximum Peak-Hour Demand (megawatts): Winter 9,300 9,478 8,863 7,757 8,478 Summer 10,241 11,019 10,739 10,329 9,778 Annual Load Factor (percent) 62.5 59.3 59.7 62.9 62.7 Plant Availability (percent): Fossil-steam 87.1 89.4 80.4 85.6 86.3 Nuclear 83.7 88.3 91.0 80.2 88.8 ------------------------------------------------------------------------------------------------------------------------------ Source of Energy Supply (percent): Coal 56.8 63.0 64.1 65.3 65.7 Nuclear 15.8 16.9 17.8 16.3 17.9 Hydro 5.1 2.9 4.7 6.9 7.5 Oil and gas 10.7 4.9 1.1 1.5 0.7 Purchased power - From non-affiliates 4.4 4.6 4.5 3.3 2.4 From affiliates 7.2 7.7 7.8 6.7 5.8 ------------------------------------------------------------------------------------------------------------------------------ Total 100.0 100.0 100.0 100.0 100.0 ==============================================================================================================================
II-79 GEORGIA POWER COMPANY FINANCIAL SECTION II-80 MANAGEMENT'S REPORT Georgia Power Company 2001 Annual Report The management of Georgia Power Company has prepared this annual report and is responsible for the financial statements and related information. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements. The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls based upon the recognition that the cost of the system should not exceed its benefits. The Company believes that its system of internal accounting controls maintains an appropriate cost/benefit relationship. The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. The audit committee of the board of directors, which is composed of three independent directors, provides a broad overview of management's financial reporting and control functions. At least three times a year this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal control and financial reporting matters. The internal auditors and the independent public accountants have access to the members of the audit committee at any time. Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted with a high standard of business ethics. In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of Georgia Power Company in conformity with accounting principles generally accepted in the United States. /s/David M. Ratcliffe David M. Ratcliffe President and Chief Executive Officer /s/Thomas A. Fanning Executive Vice President, Treasurer and Chief Financial Officer February 13, 2002 II-81 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Georgia Power Company: We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, 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, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements (pages II-93 through II-113) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2001, Georgia Power Company changed its method of accounting for derivative instruments and hedging activities. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 II-82 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 2001 Annual Report RESULTS OF OPERATIONS Earnings Georgia Power Company's 2001 earnings totaled $610 million, representing a $51 million (9.1 percent) increase over 2000. Although operating income is lower due to the impact of mild weather on retail revenues, overall net income improved due to lower financing costs and non-operating expenses and a lower effective tax rate resulting from various factors including property donations and positive resolution of outstanding tax issues. The Company's 2000 earnings totaled $559 million, representing an $18 million (3.3 percent) increase over 1999. This earnings increase was primarily due to higher retail and wholesale sales and continued control of operating expenses, partially offset by additional accelerated amortization of regulatory assets allowed under the second year of a Georgia Public Service Commission (GPSC) three-year retail rate order. Revenues Operating revenues in 2001 and the amount of change from the prior year are as follows: Increase (Decrease) From Prior Year Amount ------------------- 2001 2001 2000 ---- ------------------- Retail - (in millions) Base revenues $3,102 $(17) $ 84 Fuel cost recovery 1,247 49 183 ------------------------------------------------------------------- Total retail 4,349 32 267 ------------------------------------------------------------------- Sales for resale - Non-affiliates 366 68 88 Affiliates 100 4 20 ------------------------------------------------------------------- Total sales for resale 466 72 108 ------------------------------------------------------------------- Other operating revenues 151 (9) 39 ------------------------------------------------------------------- Total operating revenues $4,966 $95 $414 =================================================================== Percent change 2.0% 9.3% ------------------------------------------------------------------- Retail base revenues of $3.1 billion in 2001 decreased $17 million (0.5 percent) from 2000 primarily due to a 2.5 percent decrease in retail sales from the prior year. Milder-than-normal weather and a slowdown in the economy contributed to the decline in such sales. Retail base revenues of $3.1 billion in 2000 increased $84 million (2.8 percent) from 1999 primarily due to a 4.9 percent increase in sales. Under the prior GPSC retail rate order, the Company recorded $44 million of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity in 2000. These refunds were made to customers in 2001. See Note 3 to the financial statements under "Retail Rate Orders" for additional information. Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses -- including the fuel component of purchased energy -- and do not affect net income. However, cash flow is affected by the untimely recovery of these receivables. As of December 31, 2001, the Company had $162 million in underrecovered fuel costs. The Company is currently collecting these underrecovered fuel costs under a GPSC rate order issued on May 24, 2001. The fuel cost recovery rate was increased effective June 2001 to allow for a 24-month recovery of the deferred underrecovered fuel costs. Wholesale revenues from sales to non-affiliated utilities increased in 2001 and 2000 as follows: 2001 2000 1999 ----------------------------- (in millions) Long-term contracts $ 61 $ 55 $ 55 Other sales 305 243 155 ------------------------------------------------------------- Total $366 $298 $210 ============================================================= Revenues from long-term contracts increased slightly in 2001 due to increased energy sales while remaining constant in 2000. See Note 7 to the financial statements for further information regarding these sales. Revenues from other non-affiliated sales increased $62 million (25.5 percent) primarily due to increases in off-system sale transactions that were generally offset by corresponding purchase transactions. These transactions had no significant effect on income. Revenues from sales to affiliated companies within the Southern electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These transactions do not have a significant impact on earnings. Other operating revenues in 2001 decreased $9 million (5.3 percent) primarily due to lower gains on the sale of generating plant emission allowances, partially offset by increased revenues from the transmission of electricity and from the rental of electric equipment and property. Other II-83 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report operating revenues in 2000 increased $39 million (33 percent) primarily due to increased revenues from the transmission of electricity and gains on the sale of generating plant emission allowances. Under a GPSC order, $28 million of the gains on emission allowance sales in 2000 were used to reduce recoverable fuel costs and, as such, did not affect earnings. Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as follows: Percent Change ---------------------- 2001 KWH 2001 2000 --------- ------------------------ (in billions) Residential 20.1 (2.8)% 6.6% Commercial 26.5 3.4 8.1 Industrial 25.4 (8.0) 0.9 Other 0.6 2.5 3.2 ------ Total retail 72.6 (2.5) 4.9 ------ Sales for resale - Non-affiliates 8.1 25.5 27.7 Affiliates 3.1 28.7 35.6 ------ Total sales for resale 11.2 26.3 29.8 ------ Total sales 83.8 0.5 7.1 ====== ------------------------------------------------------------ Residential sales decreased 2.8 percent due to milder-than-normal weather. Commercial sales increased 3.4 percent due to a 2.8 percent increase in customers, while industrial sales decreased 8.0 percent due to an economic slowdown. Residential and commercial sales increased 6.6 percent and 8.1 percent, respectively, in 2000 due to warmer summer temperatures and colder winter weather. Strong regional economic growth was also a factor in the increase in commercial sales. Industrial sales remained fairly constant. Expenses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net KWH generated were as follows: 2001 2000 1999 -------------------------- Total generation (billions of KWH) 68.9 73.6 69.3 Sources of generation (percent) -- Coal 74.9 75.8 75.5 Nuclear 23.2 21.2 21.6 Hydro 1.4 0.8 1.0 Oil and gas 0.5 2.2 1.9 Average cost of fuel per net KWH generated (cents) -- 1.38 1.39 1.34 -------------------------------------------------------------- Fuel expense decreased 7.7 percent due to a decrease in generation because of lower energy demands and a slightly lower average cost of fuel. Fuel expense increased 10.7 percent in 2000 due to an increase in generation to meet higher energy demands, a decrease in generation from hydro plants, and a higher average cost of fuel. Purchased power expense increased $175 million (29.4 percent) in 2001 primarily due to an increase in off-system purchases used to meet off-system sales commitments. These transactions had no significant effect on earnings. Purchased power expense in 2000 increased $206 million (53 percent) over the prior year due to higher retail energy demands and off-system purchase transactions used to meet off-system sales transactions. In 2001, other operation and maintenance expenses increased $41 million (3.4%) due to additional severance costs, increased scheduled generating plant maintenance, and higher uncollectible account expense. Other operation and maintenance expenses in 2000 increased slightly over those in 1999. Increased line maintenance, customer assistance and sales expense, and severance costs were partially offset by decreased generating plant maintenance and decreased employee benefit provisions. Depreciation and amortization decreased $19 million in 2001 primarily due to lower accelerated amortization under the third year of a GPSC retail rate order. Depreciation and amortization increased $66 million in 2000 primarily due to $50 million of additional accelerated amortization of regulatory assets required under the second year of the GPSC retail rate order and increased plant in service. II-84 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report Other, net increased in 2001 due to gains realized on sales of assets and a decrease in charitable contributions. Other, net decreased in 2000 due to an increase in charitable contributions. Interest expense, net decreased in 2001 primarily due to lower interest rates that offset new financing costs. Interest expense, net increased in 2000 due to the issuance of additional senior notes during 2000. The Company refinanced or retired $775 million and $179 million of securities in 2001 and 2000, respectively. Distributions on preferred securities of subsidiary companies remained unchanged in 2001 and decreased $7 million in 2000 due to the redemption of $100 million of preferred securities in December 1999. Effects of Inflation The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plants with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed. FUTURE EARNINGS POTENTIAL General The results of operations for the past three years are not necessarily indicative of future earnings. The level of future earnings depends on numerous factors including regulatory matters and energy sales. Growth in energy sales is subject to a number of factors which traditionally have included changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, weather, competition, initiatives to increase sales to existing customers, and the rate of economic growth in the Company's service area. In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income of approximately $60 million in 2001. Future pension income is dependent on several factors including trust earnings and changes to the plan. For the Company, pension income is a component of the regulated rates and does not have a significant effect on net income. For additional information, see Note 2 to the financial statements. The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the State of Georgia. Prices for electricity provided by the Company to retail customers are set by the GPSC under cost-based regulatory principles. On December 20, 2001, the GPSC approved a new three-year retail rate order for the Company ending December 31, 2004. Under the terms of the order, earnings will be evaluated annually against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will be applied to rate refunds, with the remaining one-third retained by the Company. Retail rates were decreased by $118 million effective January 1, 2002. Pursuant to a previous three-year accounting order, the Company recorded $336 million of accelerated cost amortization and interest thereon which has been credited to a regulatory liability account as mandated by the GPSC. Under the new rate order, the accelerated amortization and the interest will be amortized equally over three years as a credit to expense beginning in 2002. The Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. Georgia Power is required to file a general rate case on July 1, 2004, in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued. See Note 3 to the financial statements under "Retail Rate Orders" for additional information. The Company has entered into power purchase agreements which will result in higher capacity and operating and maintenance payments in future years. Under the new retail rate order, these costs will be reflected in rates evenly over the next three years. See Note 4 to the financial statements under "Purchased Power Commitments" for additional information. II-85 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report Georgia Power had three new generation projects under construction during 2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion turbine facility; two combined cycle units totaling 1,132 megawatts at Plant Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle facility. All three of these projects have been transferred to Southern Power Company, a new Southern Company subsidiary formed in 2001 to construct, own, and manage wholesale generating assets in the Southeast. The ten Dahlberg units and two Goat Rock units were transferred in 2001 and the transfer of the two Wansley units was completed in January 2002. The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings. Compliance costs related to current and future environmental laws, regulations, and litigation could affect earnings if such costs are not fully recovered. See "Environmental Issues" for further discussion of these matters. Industry Restructuring The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it has been a major catalyst for recent restructuring and consolidations taking place within the utility industry. Numerous federal and state initiatives are in varying stages that promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While restructuring and competition initiatives have been discussed in Georgia, none have been enacted. Enactment would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California. As a result of that crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. The Company does compete with other electric suppliers within the state. In Georgia, most new retail customers with at least 900 kilowatts of connected load may choose their electricity supplier. In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing an RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In January 2002, the sponsors of SeTrans held a public meeting to form a Stakeholder Advisory Committee, which will participate in the development of the RTO. Southern Company continues to work with the other sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to have a material impact on Georgia Power's financial statements. The outcome of this matter cannot now be determined. Accounting Policies Critical Policy Georgia Power's significant accounting policies are described in Note 1 to the financial statements. The Company's most critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets, including plant, have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information. II-86 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report New Accounting Standards Effective January 2001, Georgia Power adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Statement No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value, and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. See Note 1 to the financial statements under "Financial Instruments" for additional information. The impact on net income in 2001 was not material. An additional interpretation of Statement No. 133 will result in a change -- effective April 1, 2002 -- in accounting for certain contracts related to fuel supplies that contain quantity options. These contracts will be accounted for as derivatives and marked to market. However, due to the existence of specific cost-based fuel recovery clauses for the Company, this change is not expected to have a material impact on net income. In June 2001, the FASB issued Statement No. 142, Goodwill and Other Intangible Assets, which establishes new accounting and reporting standards for acquired goodwill and other intangible assets and supersedes Accounting Principles Board Opinion No. 17. Statement No. 142 addresses how intangible assets that are acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for upon acquisition and on an ongoing basis. Goodwill and intangible assets that have indefinite useful lives will not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives, which are no longer limited to 40 years. The Company adopted Statement No. 142 effective January 1, 2002 with no material impact on the Company's financial statements. Also, in June 2001, the FASB issued Statement No. 143, Asset Retirement Obligations, which establishes new accounting and reporting standards for legal obligations associated with retiring assets, including decommissioning nuclear plants. The liability for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The Company has not yet quantified the impact of adopting Statement No. 143 on its financial statements. FINANCIAL CONDITION Plant Additions In 2001, gross utility plant additions were $1.4 billion. These additions were primarily related to transmission and distribution facilities, the purchase of nuclear fuel, and the construction of additional combustion turbine and combined cycle units. The funds needed for gross property additions are currently provided from operations, short-term and long-term debt, and capital contributions from Southern Company. The Statements of Cash Flows provide additional details. Credit Rating Risk The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain physical electricity sale contracts that could require collateral -- but not termination -- in the event of a credit rating change to below investment grade. At December 31, 2001, the maximum potential collateral requirements were approximately $112 million. Exposure to Market Risks The Company is exposed to market risks, including changes in interest rates, currency exchange rates, and certain commodity prices. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis. The Company's market risk exposures relative to interest rate changes have not changed materially compared to the previous reporting period. In addition, the Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. II-87 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $13 million at December 31, 2001. Based on the Company's overall interest rate exposure at December 31, 2001, including derivative and other interest rate sensitive instruments, a near-term 100 basis point change in interest rates would not materially affect the Company's financial statements. Due to cost-based rate regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company entered into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and to a lesser extent similar contracts for gas purchases. Realized gains and losses are recognized in the Statements of Income as incurred. At December 31, 2001, exposure from these activities was not material to the Company's financial statements. Fair value of changes in energy trading contracts and year-end valuations are as follows: Changes During the Year ---------------------------------------------------- Fair Value ---------------------------------------------------- (in millions) Contracts beginning of year $0.9 Contracts realized or settled (0.6) New contracts at inception - Changes in valuation techniques - Current period changes 0.1 ---------------------------------------------------- Contracts end of year $0.4 =================================================== All of these contracts are actively quoted and mature within one year. For additional information, see Note 1 to the financial statements under "Financial Instruments." Financing Activities In 2001, the Company's financing costs decreased due to lower interest rates despite the issuance of new debt during the year. New issues during 1999 through 2001 totaled $1.9 billion and retirement or repayment of higher-cost securities totaled $1.7 billion. The proceeds from assets transferred to Southern Power were used to reduce short-term debt and return capital to the Southern Company that was used during the construction of these projects. Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 1999 through 2001, as of year-end, were as follows: 2001 2000 1999 -------------------------------- Composite interest rate on long-term debt 4.26% 5.90% 5.48% Composite preferred stock dividend rate 4.60 4.60 4.60 Composite preferred securities dividend rate 7.49 7.49 7.49 ---------------------------------------------------------------- Liquidity and Capital Requirements Cash provided from operations remained constant in 2001. The Company estimates that construction expenditures for the years 2002 through 2004 will total $1.0 billion, $0.8 billion, and $0.8 billion, respectively. Investments primarily in additional transmission and distribution facilities and equipment to comply with environmental requirements are planned. Cash requirements for redemptions announced and maturities of long-term debt are expected to total $666 million during 2002 through 2004. As a result of requirements by the Nuclear Regulatory Commission, the Company has established external trust funds for the purpose of funding nuclear decommissioning costs. The amount to be funded under the new GPSC rate order is $8.7 million each year in 2002, 2003, and 2004. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning." Sources of Capital The Company expects to meet future capital requirements primarily using funds generated from operations and equity funds from Southern Company and by the issuance of new debt and equity securities, term loans, and short-term borrowings. The Company plans to request new financing authority from the GPSC in early 2002 to allow for the issuance of new long-term securities. To meet short-term cash needs and contingencies, the Company had approximately $1.8 billion of unused credit arrangements with banks at the beginning of 2002. See Note 9 to the financial statements under "Bank Credit Arrangements" for additional information. II-88 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company operating companies. At December 31, 2001, the Company had outstanding $707.6 million of commercial paper. Recently, the Company has relied on the issuance of unsecured debt and trust preferred securities, in addition to unsecured pollution control bonds issued for its benefit by public authorities, to meet its long-term external financing requirements. In years past, the Company issued first mortgage bonds, mortgage backed pollution control bonds and preferred stock to fund its external requirements. The amount outstanding of these securities has been steadily declining during the last four years. Other Capital Requirements In addition to the funds needed for the construction program, approximately $666 million will be required by the end of 2004 for maturities of long-term debt. Also, the Company will continue to retire higher-cost debt and preferred securities and replace these obligations with lower-cost capital if market conditions permit. These capital requirements, lease obligations, and purchase commitments -- discussed in Notes 4 and 9 to the financial statements -- are as follows: 2002 2003 2004 --------------------------------------------------------------- (in millions) Bonds - First mortgage $ 2 $ - $ - Pollution control 8 - - Notes 300 350 - Leases - Capital 2 2 2 Operating 15 15 15 Purchase commitments Fuel 1,234 1,115 617 Purchased power 163 223 278 --------------------------------------------------------------- At the beginning of 2002, Georgia Power had not used any of its available credit arrangements. Credit arrangements are as follows: Expires ---------------------------- Total Unused 2002 2003 & beyond ------------------------------------------------------ (in millions) $1,765 $1,765 $1,265 $500 ------------------------------------------------------ ENVIRONMENTAL ISSUES Clean Air Legislation In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Southern Company's subsidiaries, including the Company. Reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995. Southern Company's subsidiaries, including the Company, achieved Phase I compliance at the affected units by primarily switching to low-sulfur coal and with some equipment upgrades. Construction expenditures for the Company's Phase I compliance totaled approximately $167 million. Phase II sulfur dioxide compliance was required in 2000. Southern Company's subsidiaries, including the Company, used emission allowances and fuel switching to comply with Phase II requirements. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment requirements increased total construction expenditures for the Company through 2000 by approximately $39 million. In 2000, the State of Georgia established new emission limits designed to help bring the Atlanta area into compliance with the national one-hour standard for ground-level ozone. The limits include new emission standards for seven of the Company's generating stations and will go into effect in May 2003. Construction expenditures for the Company's compliance with these new rules are currently estimated at approximately $699 million with a total of $345 million remaining to be spent. II-89 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered. In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals is considering other legal challenges to these standards. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued regional nitrogen oxide reduction rules to the states for implementation. The final rule affects 21 states including Georgia. Compliance is required by May 31, 2004. The EPA proposed rules for Georgia on February 13, 2002. The EPA's proposal includes a May 1, 2005 implementation date for Georgia. The Company plans to demonstrate compliance based largely on NOx controls already installed to meet the Atlanta non-attainment requirements, coupled with the purchase of NOx credits within a NOx trading market. In December 2000, having completed its utility study for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is to be developed under the Maximum Achievable Control Technology provisions of the Clean Air Act, and regulations are scheduled to be finalized by the end of 2004 with implementation to take place around 2007. In January 2001, the EPA proposed guidance for the determination of Best Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls is expected to take place around 2010. Litigation of the Regional Haze Regulations, including the BART provisions, is ongoing in the Federal District of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002. Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide and reductions in mercury and other HAPS emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. In October 1997, the EPA issued regulations setting forth requirements for Compliance Assurance Monitoring (CAM) in state and federal operating permit programs. These regulations were amended by the EPA in March 2001 in response to a court order resolving challenges to the rules brought by environmental groups and industry. Generally, this rule affects the operation and maintenance of electrostatic precipitators and could involve significant additional ongoing expense. The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. Environmental Protection Agency Litigation On November 3, 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Bowen and Scherer plants. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued a notice of violation to the Company relating to these two plants. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the II-90 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The case against the Company has been stayed since the spring of 2001 pending a ruling by the federal Court of Appeals for the Eleventh Circuit in the appeal of a very similar Clean Air Act / New Source Review enforcement action brought by EPA against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA case could have a significant adverse impact on Georgia Power, the Company is a party to that case as well. The federal court in Georgia is currently considering a motion by the EPA to reopen the case. The Company has opposed that motion. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. Other Environmental Issues The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur costs to clean up properties currently or previously owned. The Company conducts studies to determine the extent of any required clean-up and has recognized in the financial statements costs to clean up known sites. These costs for the Company amounted to $0.6 million in 2001 and $4 million in both 2000 and 1999. Additional sites may require environmental remediation for which the Company may be liable for all or a portion of required clean-up costs. See Note 3 to the financial statements under "Other Environmental Contingencies" for information regarding the Company's potentially responsible party status at sites in Georgia. Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect the Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields. CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION The Company's 2001 Annual Report includes forward-looking statements in addition to historical information. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "projects," "potential" or "continue" or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental 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, including the pending EPA civil action and the race discrimination litigation against the Company; the effect, extent, and timing of the entry of additional competition in the markets in which the Company operates; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; the effects of, and changes in economic conditions in the areas in which the Company operates; internal restructuring or other restructuring options that may be pursued by the Company; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or II-91 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2001 Annual Report beneficial; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission. II-92
STATEMENTS OF INCOME For the Years Ended December 31, 2001, 2000, and 1999 Georgia Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------- 2001 2000 1999 ------------------------------------------------------------------------------------------------------------- (in thousands) Operating Revenues: Retail sales $4,349,312 $4,317,338 $4,050,088 Sales for resale -- Non-affiliates 366,085 297,643 210,104 Affiliates 99,411 96,150 76,426 Other revenues 150,986 159,487 120,057 ------------------------------------------------------------------------------------------------------------- Total operating revenues 4,965,794 4,870,618 4,456,675 ------------------------------------------------------------------------------------------------------------- Operating Expenses: Operation -- Fuel 939,092 1,017,878 919,876 Purchased power -- Non-affiliates 442,196 356,189 214,573 Affiliates 329,232 239,815 174,989 Other 810,043 795,458 784,359 Maintenance 430,413 404,189 411,983 Depreciation and amortization 600,631 619,094 552,966 Taxes other than income taxes 202,483 204,527 202,853 ------------------------------------------------------------------------------------------------------------- Total operating expenses 3,754,090 3,637,150 3,261,599 ------------------------------------------------------------------------------------------------------------- Operating Income 1,211,704 1,233,468 1,195,076 Other Income (Expense): Interest income 4,264 2,629 5,583 Equity in earnings of unconsolidated subsidiaries 4,178 3,051 2,721 Other, net (2,816) (50,495) (47,986) ------------------------------------------------------------------------------------------------------------- Earnings Before Interest and Income Taxes 1,217,330 1,188,653 1,155,394 ------------------------------------------------------------------------------------------------------------- Interest Charges and Other: Interest expense, net 183,879 208,868 194,869 Distributions on preferred securities of subsidiaries 59,104 59,104 65,774 ------------------------------------------------------------------------------------------------------------- Total interest charges and other, net 242,983 267,972 260,643 ------------------------------------------------------------------------------------------------------------- Earnings Before Income Taxes 974,347 920,681 894,751 Income taxes 363,599 360,587 351,639 ------------------------------------------------------------------------------------------------------------- Net Income Before Cumulative Effect of Accounting Change 610,748 560,094 543,112 Cumulative effect of accounting change -- less income taxes of $162 thousand 257 - - ------------------------------------------------------------------------------------------------------------- Net Income 611,005 560,094 543,112 Dividends on Preferred Stock 670 674 1,729 ------------------------------------------------------------------------------------------------------------- Net Income After Dividends on Preferred Stock $ 610,335 $ 559,420 $ 541,383 ============================================================================================================= The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001, 2000, and 1999 Georgia Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Activities: Net income $ 611,005 $ 560,094 $ 543,112 Adjustments to reconcile net income to net cash provided from operating activities -- Depreciation and amortization 697,143 712,960 663,878 Deferred income taxes and investment tax credits, net (48,329) (28,961) (34,930) Other, net (92,403) (51,501) (42,179) Changes in certain current assets and liabilities -- Receivables, net 60,914 (108,621) 21,665 Fossil fuel stock (103,296) 26,835 (22,165) Materials and supplies (15,628) (9,715) (10,417) Accounts payables (15,406) 64,412 13,095 Energy cost recovery, retail (29,839) (95,235) (26,862) Other (2,999) (9,092) 90,788 ------------------------------------------------------------------------------------------------------------------------------- Net cash provided from operating activities 1,061,162 1,061,176 1,195,985 ------------------------------------------------------------------------------------------------------------------------------- Investing Activities: Gross property additions (1,389,751) (1,078,163) (790,464) Sales of property 534,760 - - Other (4,774) (5,450) (27,454) ------------------------------------------------------------------------------------------------------------------------------- Net cash used for investing activities (859,765) (1,083,613) (817,918) ------------------------------------------------------------------------------------------------------------------------------- Financing Activities: Increase in notes payable, net 43,698 67,598 295,389 Proceeds -- Senior notes 600,000 300,000 100,000 Pollution control bonds 404,535 78,725 238,000 Preferred securities - - 200,000 Capital contributions from parent company 225,060 301,514 155,777 Retirements -- First mortgage bonds (390,140) (100,000) (404,000) Pollution control bonds (385,035) (78,725) (235,000) Preferred securities - - (100,000) Preferred stock - (383) (36,231) Capital distributions to parent company (160,000) - - Payment of preferred stock dividends (578) (751) (984) Payment of common stock dividends (527,300) (549,600) (543,000) Other (17,747) (1,231) (29,630) ----------------------------------------------------------------------------------------------------------------------------- Net cash provided from (used for) financing activities (207,507) 17,147 (359,679) ----------------------------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents (6,110) (5,290) 18,388 Cash and Cash Equivalents at Beginning of Year 29,370 34,660 16,272 ----------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $23,260 $29,370 $34,660 ----------------------------------------------------------------------------------------------------------------------------- Supplemental Cash Flow Information: Cash paid during the year for -- Interest (net of amount capitalized) $ 234,456 $ 265,373 $ 247,050 Income taxes (net of refunds) 381,995 392,310 394,457 ----------------------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of these statements.
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BALANCE SHEETS At December 31, 2001 and 2000 Georgia Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------ Assets 2001 2000 ------------------------------------------------------------------------------------------------------------------ (in thousands) Current Assets: Cash and cash equivalents $ 23,260 $ 29,370 Receivables -- Customer accounts receivable 376,322 465,249 Underrecovered retail fuel clause revenue 161,462 131,623 Other accounts and notes receivable 129,073 156,143 Affiliated companies 87,786 13,312 Accumulated provision for uncollectible accounts (8,895) (5,100) Fossil fuel stock, at average cost 202,759 99,463 Materials and supplies, at average cost 279,237 263,609 Other 125,246 97,515 ------------------------------------------------------------------------------------------------------------------ Total current assets 1,376,250 1,251,184 ------------------------------------------------------------------------------------------------------------------ Property, Plant, and Equipment: In service 16,886,399 16,469,706 Less accumulated provision for depreciation 7,243,209 6,914,512 ------------------------------------------------------------------------------------------------------------------ 9,643,190 9,555,194 Nuclear fuel, at amortized cost 112,771 120,570 Construction work in progress (Note 4) 883,285 652,264 ------------------------------------------------------------------------------------------------------------------ Total property, plant, and equipment 10,639,246 10,328,028 ------------------------------------------------------------------------------------------------------------------ Other Property and Investments: Equity investments in unconsolidated subsidiaries (Note 4) 35,209 29,569 Nuclear decommissioning trusts 364,180 375,666 Other 29,618 29,745 ------------------------------------------------------------------------------------------------------------------ Total other property and investments 429,007 434,980 ------------------------------------------------------------------------------------------------------------------ Deferred Charges and Other Assets: Deferred charges related to income taxes (Note 8) 543,584 565,982 Prepaid pension costs 228,259 147,271 Debt expense, being amortized 58,165 53,748 Premium on reacquired debt, being amortized 173,724 173,610 Other 117,706 120,964 ------------------------------------------------------------------------------------------------------------------ Total deferred charges and other assets 1,121,438 1,061,575 ------------------------------------------------------------------------------------------------------------------ Total Assets $13,565,941 $13,075,767 ================================================================================================================== The accompanying notes are an integral part of these balance sheets.
II-95
BALANCE SHEETS At December 31, 2001 and 2000 Georgia Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------------- Liabilities and Stockholder's Equity 2001 2000 -------------------------------------------------------------------------------------------------------------------- (in thousands) Current Liabilities: Securities due within one year (Note 9) $ 311,620 $ 1,808 Notes payable 747,537 703,839 Accounts payable -- Affiliated 109,591 117,168 Other 409,253 397,550 Customer deposits 83,172 78,540 Taxes accrued -- Income taxes 35,247 5,151 Other 125,807 137,511 Interest accrued 46,942 47,244 Vacation pay accrued 41,830 38,865 Other 112,686 137,565 -------------------------------------------------------------------------------------------------------------------- Total current liabilities 2,023,685 1,665,241 -------------------------------------------------------------------------------------------------------------------- Long-term debt (See accompanying statements) 2,961,726 3,041,939 -------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes (Note 8) 2,163,959 2,182,783 Deferred credits related to income taxes (Note 8) 229,216 247,067 Accumulated deferred investment tax credits (Note 8) 337,482 352,282 Employee benefits provisions 207,795 191,587 Other 440,774 341,505 -------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 3,379,226 3,315,224 -------------------------------------------------------------------------------------------------------------------- Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding company junior subordinated notes (See accompanying statements) 789,250 789,250 -------------------------------------------------------------------------------------------------------------------- Cumulative preferred stock (See accompanying statements) 14,569 14,569 -------------------------------------------------------------------------------------------------------------------- Common stockholder's equity (See accompanying statements) 4,397,485 4,249,544 -------------------------------------------------------------------------------------------------------------------- Total Liabilities and Stockholder's Equity $13,565,941 $13,075,767 ==================================================================================================================== The accompanying notes are an integral part of these balance sheets.
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STATEMENTS OF CAPITALIZATION At December 31, 2001 and 2000 Georgia Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Long-Term Debt: First mortgage bonds Maturity Interest Rates -------- ------------- April 1, 2003 6.625% $ - $ 200,000 August 1, 2003 6.35% - 75,000 2005 6.07% 1,860 10,000 2008 6.875% - 50,000 2025 7.70% - 57,000 -------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 1,860 392,000 -------------------------------------------------------------------------------------------------------------- Senior notes -- (Note 9) Variable rate (1.98125% at 1/1/02) due February 22, 2002 300,000 300,000 5.75% due January 31, 2003 200,000 - 5.25% due May 8, 2003 150,000 - 5.50% due December 1, 2005 150,000 150,000 6.20% due February 1, 2006 150,000 - 6.70% due March 1, 2011 100,000 - 6.60% due December 31, 2038 200,000 200,000 6.625% due March 31, 2039 100,000 100,000 6.875% due December 31, 2047 145,000 145,000 -------------------------------------------------------------------------------------------------------------- Total senior notes payable 1,495,000 895,000 -------------------------------------------------------------------------------------------------------------- Other long-term debt -- (Note 9) Pollution control revenue bonds -- Maturity Interest Rates ------- ------------- 2005 5.00% - 57,000 2011 Variable (1.90% to 1.95% at 1/1/02) 10,450 10,450 2012-2016 4.20% to 5.00% 164,590 - 2018-2021 6.00% to 6.25% 7,800 23,225 2018 Variable (2.00% at 1/1/02) 19,500 - 2023-2025 4.90% to 6.75% 28,065 298,535 2022-2026 Variable (1.75% to 1.95% at 1/1/02) 669,480 683,555 2029 Variable (1.90% to 1.95% at 1/1/02) 144,700 144,700 2030-2031 4.53% to 5.25% 137,570 78,725 2032-2034 Variable (1.75% to 1.95% at 1/1/02) 140,000 140,000 2032-2034 4.45% to 5.45% 371,535 238,000 -------------------------------------------------------------------------------------------------------------- Total other long-term debt 1,693,690 1,674,190 -------------------------------------------------------------------------------------------------------------- Capital lease obligations (Note 9) 83,371 85,179 -------------------------------------------------------------------------------------------------------------- Unamortized debt discount, net (575) (2,622) -------------------------------------------------------------------------------------------------------------- Total long-term debt (annual interest) requirement -- $139.5 million) 3,273,346 3,043,747 Less amount due within one year (Note () 311,620 1,808 ----------------------------------------------------------------------------------------------------------------------------------- Total long-term debt excluding amount due within one year $ 2,961,726 $ 3,041,939 36.3 % 37.6 % -----------------------------------------------------------------------------------------------------------------------------------
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STATEMENTS OF CAPITALIZATION (continued) At December 31, 2001 and 2000 Georgia Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Company Obligated Mandatorily Redeemable Preferred Securities (Note 9): $25 liquidation value -- 6.85% $ 200,000 $ 200,000 $25 liquidation value -- 7.60% 175,000 175,000 $25 liquidation value -- 7.75% 189,250 189,250 $25 liquidation value -- 7.75% 225,000 225,000 ----------------------------------------------------------------------------------------------------------------------------------- Total (annual distribution requirement -- $59.1 million) 789,250 789,250 9.6 9.7 ----------------------------------------------------------------------------------------------------------------------------------- Cumulative Preferred Stock, without par value: Authorized -- 55,000,000 shares Outstanding -- 145,689 shares at December 31, 2001 Outstanding -- 145,689 shares at December 31, 2000 $100 stated value -- 4.60% 14,569 14,569 ----------------------------------------------------------------------------------------------------------------------------------- Total cumulative preferred stock (annual dividend requirement -- $0.7 million) 14,569 14,569 0.2 0.2 ----------------------------------------------------------------------------------------------------------------------------------- Common Stockholder's Equity: Common stock, without par value -- Authorized -- 15,000,000 shares Outstanding -- 7,761,500 shares 344,250 344,250 Paid-in capital 2,182,557 2,117,497 Premium on preferred stock 40 40 Other comprehensive income (153) - Retained earnings (Note 9) 1,870,791 1,787,757 ----------------------------------------------------------------------------------------------------------------------------------- Total common stockholder's equity (See accompanying statements) 4,397,485 4,249,544 53.9 52.5 ----------------------------------------------------------------------------------------------------------------------------------- Total Capitalization $ 8,163,030 $ 8,095,302 100.0 % 100.0 % ----------------------------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of these statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2001, 2000, and 1999 Georgia Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------- Premium on Other Common Paid-In Preferred Retained Comprehensive Stock Capital Stock Earnings Income (Loss) Total ------------------------------------------------------------------------------------------------------------------------------ Balance at January 1, 1999 $344,250 $1,660,206 $158 $1,779,558 $ - $3,784,172 Net income after dividends on preferred stock - - - 541,383 - 541,383 Capital contributions from parent company - 155,777 - - - 155,777 Cash dividends on common stock - - - (543,000) - (543,000) Preferred stock transactions, net - - (118) (4) - (122) ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 344,250 1,815,983 40 1,777,937 - 3,938,210 Net income after dividends on preferred stock - - - 559,420 - 559,420 Capital contributions from parent company - 301,514 - - - 301,514 Cash dividends on common stock - - - (549,600) - (549,600) ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 344,250 2,117,497 40 1,787,757 - 4,249,544 Net income after dividends on preferred stock - - - 610,335 - 610,335 Capital contributions from parent company - 225,060 - - - 225,060 Capital distributions to parent company (160,000) (160,000) Other comprehensive income - - - - (153) (153) Cash dividends on common stock - - - (527,300) - (527,300) Preferred stock transactions, net - - - (1) - (1) ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 $344,250 $2,182,557 $40 $1,870,791 ($153) $4,397,485 ===============================================================================================================================
STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2001, 2000, and 1999 Georgia Power Company 2001 Annual Report --------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------------- (in thousands) Net income after dividends on preferred stock $ 610,335 $ 559,420 $ 541,383 Other comprehensive income: Cumulative effect of accounting change, net of tax 286 - - Current period changes in fair value, net of tax (439) - - --------------------------------------------------------------------------------------------------------------------------- Comprehensive Income $ 610,182 $ 559,420 $ 541,383 =========================================================================================================================== The accompanying notes are an integral part of these statements.
II-99 NOTES TO FINANCIAL STATEMENTS Georgia Power Company 2001 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General The Company is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company (SCS), Southern Communications Services (Southern LINC), Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern Power), and other direct and indirect subsidiaries. The operating companies --Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company-- provide electric service in four southeastern states. Contracts among the operating companies -- related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by the respective 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 these estimates. Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation. Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $285 million, $269 million, and $253 million during 2001, 2000, and 1999, respectively. The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services; general operations, management and technical services; administrative services including procurement, accounting and statistical, employee relations, and systems and procedures services; strategic planning and budgeting services; and other services with respect to business and operations. Costs for these services amounted to $281 million in both 2001 and 2000 and $270 million in 1999. Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. See Note 3 under "Retail Rate Orders" for additional information regarding the disposition of the regulatory liability for the accelerated cost recovery recorded under the retail rate order that ended December 31, 2001. Regulatory assets and (liabilities) reflected in the Company's Balance Sheets at December 31 relate to the following: II-100 NOTES (continued) Georgia Power Company 2001 Annual Report 2001 2000 ---------------------- (in millions) Deferred income taxes $ 544 $ 566 Deferred income tax credits (229) (247) Premium on reacquired debt 174 174 Corporate building lease 54 55 Vacation pay 52 49 Postretirement benefits 28 30 Department of Energy assessments 18 21 Deferred nuclear outage costs 24 28 Accelerated cost recovery and interest (336) (230) Other, net 16 23 -------------------------------------------------------------- Total $ 345 $ 469 =============================================================== In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value. Revenues and Fuel Costs The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Georgia, and to wholesale customers in the Southeast. The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than 1 percent of revenues. Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The Company's fuel cost recovery mechanism includes provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates. Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $75 million in each of 2001 and 2000 and $74 million in 1999. The Company has contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of used nuclear fuel. The DOE failed to begin disposing of used nuclear fuel in January 1998 as required by the contracts, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity is available at Plant Vogtle to maintain full-core discharge capability for both units until the year 2014. To maintain pool discharge capability at Plant Hatch, effective June 2000, an on-site dry storage facility for Plant Hatch became operational. Sufficient dry storage capacity is believed to be available to continue dry storage operations at Plant Hatch through the life of the plant. Procurement of on-site dry storage capacity at Plant Vogtle will commence in sufficient time to maintain pool full-core discharge capability. Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is to be funded in part by a special assessment on utilities with nuclear plants. The assessment will be paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company -- based on its ownership interests -- estimates its remaining liability under this law at December 31, 2001 to be approximately $16 million. This obligation is recorded in the accompanying Balance Sheets. Depreciation and Nuclear Decommissioning Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3 percent in 2001, 2000, and 1999. 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. Depreciation expense includes an amount for the expected costs of decommissioning nuclear facilities and removal of other facilities. Nuclear Regulatory Commission (NRC) regulations require all licensees operating commercial power reactors to establish a plan for providing, with II-101 NOTES (continued) Georgia Power Company 2001 Annual Report reasonable assurance, funds for decommissioning. The Company has established external trust funds to comply with the NRC's regulations. Earnings on the trust funds are considered in determining decommissioning expense. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. The Company periodically conducts site-specific studies to estimate the actual cost of decommissioning its nuclear generating facilities. Site study cost is the estimate to decommission the facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of its retirement date. The estimated site study costs based on the most current study and ultimate costs assuming an inflation rate of 4.7 percent for the Company's ownership interests are as follows: Plant Plant Hatch Vogtle -------------------- Site study basis (year) 2000 2000 Decommissioning periods: Beginning year 2014 2027 Completion year 2042 2045 ------------------------------------------------------------- (in millions) Site study costs: Radiated structures $486 $420 Non-radiated structures 37 48 ------------------------------------------------------------- Total $523 $468 ============================================================= (in millions) Ultimate costs: Radiated structures $1,004 $1,468 Non-radiated structures 79 166 ------------------------------------------------------------- Total $1,083 $1,634 ============================================================= The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in the NRC requirements, changes in the assumptions used in making the estimates, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials, and equipment. Annual provisions for nuclear decommissioning expense are based on an annuity method as approved by the GPSC. The amounts expensed in 2001 and fund balances as of December 31, 2001 were: Plant Plant Hatch Vogtle ---------------------------------------------------------------- (in millions) Amount expensed in 2001 $20 $9 ================================================================ (in millions) Accumulated provisions: External trust funds, at fair value $229 $135 Internal reserves 20 12 ---------------------------------------------------------------- Total $249 $147 ================================================================ Effective January 1, 2002, the GPSC decreased the annual provision for decommissioning expenses to $8 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2000 of $383 million and $282 million for Plants Hatch and Vogtle, respectively. The ultimate costs associated with the 2000 NRC minimum funding requirements are $823 million and $1.03 billion for Plants Hatch and Vogtle, respectively. Significant assumptions include an estimated inflation rate of 4.7 percent and an estimated trust earnings rate of 6.5 percent. The Company expects the GPSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning. 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 decommissioning costs disclosed above do not reflect this extension. Income Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property. Allowance for Funds Used During Construction (AFUDC) AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is II-102 NOTES (continued) Georgia Power Company 2001 Annual Report not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. For the years 2001, 2000, and 1999, the average AFUDC rates were 6.33 percent, 6.74 percent, and 5.61 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 3.0 percent for 2001, 2000, and 1999. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost, less regulatory disallowances and impairments. Original cost includes: materials; labor; payroll-related costs such as taxes, pensions, and other benefits; and the cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is capitalized. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Comprehensive Income Comprehensive income -- consisting of net income and changes in the fair value of qualifying cash flow hedges, net of income taxes -- is presented in the financial statements. 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. Financial Instruments Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The impact on net income was immaterial. The Company uses derivative financial instruments to hedge exposures to fluctuations in interest rates, foreign currency exchange rates, and certain commodity prices. Gains and losses on qualifying hedges are deferred and recognized either in income or as an adjustment to the carrying amount of the hedged item when the transaction occurs. The Company 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 and its affiliates, through SCS acting as their agent, enter into commodity related forward and option contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of the Company's bulk energy purchases and sales contracts meet the definition of a derivative under Statement No. 133. In many cases, these fuel and electricity contracts qualify for normal purchase and sale exceptions under Statement No. 133 and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses, and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income. The Company's financial instruments for which the carrying amounts did not approximate fair value at December 31 were as follows: Carrying Fair Amount Value ------------------------ Long-term debt: (in millions) At December 31, 2001 $3,190 $3,190 At December 31, 2000 $2,959 $2,912 Preferred securities: At December 31, 2001 $789 $782 At December 31, 2000 $789 $761 --------------------------------------------------- ---------- The fair values for securities were based on either closing market prices or closing prices of comparable instruments. Materials and Supplies Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory II-103 NOTES (continued) Georgia Power Company 2001 Annual Report when purchased and then expensed or capitalized to plant, as appropriate, when installed. 2. RETIREMENT BENEFITS The Company has defined benefit, trusteed pension plans that cover substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all these employees may become eligible for such benefits when they retire. The Company funds postretirement trusts to the extent required by the GPSC and the FERC. In late 2000, the Company adopted several pension and postretirement benefits plan changes that had the effect of increasing benefits to both current and future retirees. The measurement date for plan assets and obligations is September 30 of each year. The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were: 2001 2000 ----------------------------------------------------------------- Discount 7.50% 7.50% Annual salary increase 5.00 5.00 Expected long-term return on plan assets 8.50 8.50 ----------------------------------------------------------------- Pension Plan Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations -------------------------- 2001 2000 --------------------------------------------------------------- (in millions) Balance at beginning of year $1,322 $1,275 Service cost 35 32 Interest cost 101 94 Benefits paid (74) (67) Actuarial gain and employee transfers 64 (12) --------------------------------------------------------------- Balance at end of year $1,448 $1,322 =============================================================== Plan Assets --------------------------- 2001 2000 ---------------------------------------------------------------- (in millions) Balance at beginning of year $2,464 $2,107 Actual return on plan assets (356) 385 Benefits paid (62) (58) Employee transfers (2) 30 ---------------------------------------------------------------- Balance at end of year $2,044 $2,464 ================================================================ The accrued pension costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------- (in millions) Funded status $ 596 $ 1,142 Unrecognized transition obligation (22) (26) Unrecognized prior service cost 98 44 Unrecognized net actuarial gain (444) (1,013) --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 228 $ 147 =============================================================== Components of the plan's net periodic cost were as follows: 2001 2000 1999 --------------------------------------------------------------- (in millions) Service cost $ 35 $ 33 $ 33 Interest cost 101 94 86 Expected return on plan assets (168) (152) (137) Recognized net actuarial gain (31) (26) (17) Net amortization 3 (1) - --------------------------------------------------------------- Net pension income $ (60) $ (52) $ (35) =============================================================== Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations ------------------------- 2001 2000 -------------------------------------------------------------- (in millions) Balance at beginning of year $495 $438 Service cost 9 7 Interest cost 39 36 Benefits paid (24) (21) Actuarial gain and employee transfers 23 35 -------------------------------------------------------------- Balance at end of year $542 $495 ============================================================== II-104 NOTES (continued) Georgia Power Company 2001 Annual Report Plan Assets --------------------------- 2001 2000 ---------------------------------------------------------------- (in millions) Balance at beginning of year $198 $177 Actual return on plan assets (26) 12 Employer contributions 47 30 Benefits paid (24) (21) ---------------------------------------------------------------- Balance at end of year $195 $198 ================================================================ The accrued postretirement costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------- (in millions) Funded status $(347) $(297) Unrecognized transition obligation 105 113 Unrecognized prior service cost 104 60 Unrecognized (gain)/loss 5 (13) Fourth quarter contributions 27 27 --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(106) $(110) =============================================================== Components of the plans' net periodic cost were as follows: 2001 2000 1999 --------------------------------------------------------------- (in millions) Service cost $ 9 $ 7 $ 8 Interest cost 39 36 30 Expected return on plan assets (19) (16) (10) Recognized net actuarial loss - - 1 Net amortization 14 12 9 --------------------------------------------------------------- Net postretirement cost $ 43 $ 39 $38 =============================================================== An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 9.25 percent for 2001, decreasing gradually to 5.25 percent through the year 2010, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2001 as follows: 1 Percent 1 Percent Increase Decrease --------------------------------------------------------------- (in millions) Benefit obligation $54 $46 Service and interest costs 5 4 =============================================================== Employee Savings Plan The Company sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2001, 2000, and 1999 were $16 million, $15 million, and $15 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General The Company is subject to certain claims and legal actions arising in the ordinary course of business. In the opinion of management, after consultation with legal counsel, the ultimate disposition of these matters is not expected to have a material adverse effect on the Company's financial condition. Retail Rate Orders On December 20, 2001, the GPSC approved a new three-year retail rate order for the Company ending December 31, 2004. Under the terms of the order, earnings will be evaluated against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will be applied to rate refunds, with the remaining one-third retained by the Company. Retail rates were decreased by $118 million effective January 1, 2002. Under a previous three-year order ending December 2001, the Company's earnings were evaluated against a retail return on common equity range of 10 percent to 12.5 percent. The order further provided for $85 million in each year, plus up to $50 million of any earnings above the 12.5 percent return during the second and third years, to be applied to accelerated amortization or depreciation of assets. Two-thirds of any additional earnings above the 12.5 percent return were applied to rate refunds, with the remaining one-third retained by the Company. Pursuant to the order, the Company recorded $336 million of accelerated amortization and interest thereon which has been credited to a regulatory liability account as mandated by the GPSC. Under the new rate order, the accelerated amortization and the interest will be amortized equally over three years as a credit to expense beginning in 2002. Effective January 1, 2002, the Company discontinued recording accelerated II-105 NOTES (continued) Georgia Power Company 2001 Annual Report depreciation and amortization. The Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. Georgia Power is required to file a general rate case on July 1, 2004, in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued. In 2000 and 1999, the Company recorded $44 million and $79 million, respectively, of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity. Refunds applicable to 2000 and 1999 were made to customers in 2001 and 2000, respectively. Environmental Protection Agency (EPA) Litigation On November 3, 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Bowen and Scherer plants. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units beginning at the point of the alleged violations. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued a notice of violation to the Company relating to these two plants. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The case against the Company has been stayed since the spring of 2001 pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar Clean Air Act / New Source Review enforcement action brought by EPA against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA case could have a significant adverse impact on Georgia Power, the Company is a party to that case as well. The federal court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. The Company has opposed that motion. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. Other Environmental Contingencies 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. Georgia Power has recognized $33 million in cumulative expenses through December 31, 2001 for the assessment and anticipated cleanup of sites on the Georgia Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia that is listed on the federal National Priorities List. Georgia Power has contributed to the removal and remedial investigation and feasibility study costs for the site. Additional claims for recovery of natural resource damages at the site are anticipated. As of December 31, 2001, Georgia Power had recorded approximately $6 million in cumulative expenses associated with Georgia Power's agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site. The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of Georgia Power's activities relating to these sites, management does not believe that the Company's cumulative liability at these sites would be material to the financial statements. II-106 NOTES (continued) Georgia Power Company 2001 Annual Report Nuclear Performance Standards The GPSC has adopted a nuclear performance standard for the Company's nuclear generating units under which the performance of Plants Hatch and Vogtle is evaluated every three years. The performance standard is based on each unit's capacity factor as compared to the average of all comparable U.S. nuclear units operating at a capacity factor of 50 percent or higher during the three-year period of evaluation. Depending on the performance of the units, the Company could receive a monetary award or penalty under the performance standards criteria. The GPSC has approved performance awards of approximately $11.7 million and $7.8 million for performance during the 1993-1995 period and the 1996-1998 period, respectively. These awards are collected through the retail fuel cost recovery provision and recognized in income over 36-month periods that began in January 1997 and 2000, respectively, as mandated by the GPSC. Race Discrimination Litigation On July 28, 2000, a lawsuit alleging race discrimination was filed by three Georgia Power employees against the Company, Southern Company, and SCS in the United States District Court for the Northern District of Georgia. The lawsuit also raised claims on behalf of a purported class. The plaintiffs seek compensatory and punitive damages in an unspecified amount, as well as injunctive relief. On August 14, 2000, the lawsuit was amended to add four more plaintiffs. Also, an additional subsidiary of Southern Company, Southern Company Energy Solutions, Inc., was named a defendant. On October 11, 2001, the district court denied plaintiffs' motion for class certification. The plaintiffs filed a motion to reconsider the order denying class certification, and the court denied the plaintiffs' motion to reconsider. On December 28, 2001, the plaintiffs filed a petition in the United States Court of Appeals for the Eleventh Circuit seeking permission to file an appeal of the October 11 decision. The defendants filed a brief in opposition of the petition on January 18, 2002. Discovery of the seven named plaintiffs' individual claims that remain in the case is ongoing. The final outcome of the case cannot be determined. 4. COMMITMENTS Construction Program Georgia Power had three new generation projects under construction during 2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion turbine facility; two combined cycle units totaling 1,132 megawatts at Plant Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle facility. All three of these projects have been transferred to Southern Power Company, a new Southern Company affiliate formed in 2001 to construct, own, and manage wholesale generating assets in the Southeast. The ten Dahlberg units and two Goat Rock units were transferred in 2001 and the transfer of the two Wansley units was completed in January 2002. Significant construction of transmission and distribution facilities and projects to remain in compliance with environmental requirements will continue. The Company currently estimates property additions to be approximately $1.0 billion in 2002, $0.8 billion in 2003, and $0.8 billion in 2004. In connection with the transfer of Plants Dahlberg, Goat Rock, and Wansley, the Company has assigned $61 million in vendor equipment contracts to Southern Power. While the Company could be obligated to assume responsibility for these contracts if Southern Power fails to meet these commitments, Southern Company has entered into limited keep-well arrangements whereby Southern Company would contribute funds to Southern Power either through loans or capital contributions in order to fund performance by Southern Power as equipment purchaser under certain contingencies. Southern Company has also guaranteed Southern Power obligations totaling $6.6 milion for the Company's construction of transmission interconnection facilities to these plants. The construction program is subject to periodic review and revision, and actual construction costs may vary from estimates because of numerous factors, including, but not limited to, changes in business conditions, load growth estimates, environmental regulations, and regulatory requirements. Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. II-107 NOTES (continued) Georgia Power Company 2001 Annual Report Total estimated long-term fossil and nuclear fuel commitments at December 31, 2001 were as follows: Minimum Year Obligations ---- ------------------- (in millions) 2002 $1,234 2003 1,115 2004 617 2005 527 2006 521 2007 and beyond 1,857 ------------------------------------------------------------- Total $5,871 ============================================================= Additional commitments for coal and for nuclear fuel will be required in the future to supply the Company's fuel needs. In addition, SCS acts as agent for the five operating companies and Southern Power with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm and disclosed in the following chart. The committed volumes, as of December 31, 2001 are as follows: Year Natural Gas ---- ------------------ (MMBtu) 2002 18,927,055 2003 30,434,645 2004 30,352,580 2005 23,050,128 2006 20,038,214 2007 and beyond 7,153,129 --------------------------------------------------------------- Total 129,955,751 =============================================================== Purchased Power Commitments The Company and an affiliate, Alabama Power, own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of the units has been sold equally to the Company and Alabama Power 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: 2001 2000 1999 --------------------------------- (in millions) Energy $52 $57 $51 Capacity 30 30 29 -------------------------------------------------------------- Total $82 $87 $80 ============================================================== The Company has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by Municipal Electric Authority of Georgia (MEAG) that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. Except as noted below, the cost of such capacity and energy is included in purchased power from non-affiliates in the Company's Statements of Income. Capacity payments totaled $59 million, $58 million, and $57 million in 2001, 2000, and 1999, respectively. The current projected Plant Vogtle capacity payments are: Year Capacity Payments ---------------------- (in millions) 2002 $ 58 2003 59 2004 55 2005 55 2006 55 2007 and beyond 483 ---------------------------------------------------------------- Total $765 ================================================================ Portions of the payments noted above relate to costs in excess of Plant Vogtle's allowed investment for ratemaking purposes. The present value of these portions was written off in 1987 and 1990. II-108 NOTES (continued) Georgia Power Company 2001 Annual Report The Company has entered into other various long-term commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2001 were as follows: Year Non- Affiliated Affiliated ---- -------------------------------- (in millions) 2002 $ 66 $ 39 2003 123 41 2004 183 40 2005 198 40 2006 197 40 2007 and beyond 1,138 396 ------------------------------------------------------------ Total $1,905 $596 ============================================================ Operating Leases The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $14 million for 2001, $16 million for 2000, and $11 million for 1999. At December 31, 2001, estimated minimum rental commitments for these noncancelable operating leases were as follows: Year Minimum Obligations ----------------------- (in millions) 2002 $ 15 2003 15 2004 15 2005 15 2006 15 2007 and beyond 91 -------------------------------------------------------------- Total $166 ============================================================== In addition to the rental commitments above, the Company has obligations upon expiration of certain of the rail car leases with respect to the residual value of the leased property. These leases expire in 2004 and 2010, and the Company's maximum obligations are $13 million and $40 million, respectively. 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. 5. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act of 1988, the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plants. The Act provides funds up to $9.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $200 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $88 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment for the Company, excluding any applicable state premium taxes -- based on its ownership and buyback interests -- is $178 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year. The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities. Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the three NEIL policies would be $39 million. II-109 NOTES (continued) Georgia Power Company 2001 Annual Report Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power stations would be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all terrorist acts. The NEIL aggregate, which applies to all claims stemming from terrorism within a 12 month duration, is $3.24 billion plus any amounts that would be available through reinsurance or indemnity from an outside source. The ANI cap is $200 million in a policy year. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies should be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. 6. JOINT OWNERSHIP AGREEMENTS Except as otherwise noted, the Company has contracted to operate and maintain all jointly owned generating facilities. The Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with Oglethorpe Power Company who is the operator of the plant. The Company also jointly owns Plant McIntosh with Savannah Electric and Power Company who operates the plant. The Company and Florida Power Corporation (FPC) jointly own a combustion turbine unit (Intercession City) operated by FPC. The Company includes its proportionate share of plant operating expenses in the corresponding operating expenses in the Statements of Income. At December 31, 2001, 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% $3,304 $1,793 Plant Hatch (nuclear) 50.1 881 668 Plant Wansley (coal) 53.5 309 152 Plant Scherer (coal) Units 1 and 2 8.4 112 56 Unit 3 75.0 545 221 Plant McIntosh Common Facilities 75.0 24 2 (combustion-turbine) Rocky Mountain 25.4 169 78 (pumped storage) Intercession City 33.3 12 1 (combustion-turbine) -------------------------------------------------------------------- 7. LONG-TERM POWER SALES AGREEMENTS The Company and the other operating companies of Southern Company have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. These agreements consist of firm unit power sales pertaining to capacity from specific generating units. Because energy is generally sold at cost under these agreements, it is primarily the capacity revenues that affect the Company's profitability. The Company's capacity revenues were as follows: Year Revenues Capacity ---------------------------------- (in millions) (megawatts) 2001 $ 26 102 2000 30 124 1999 32 162 ---------------------------------- Unit power from specific generating plants is being sold to Florida Power & Light Company, FPC, and Jacksonville Electric Authority. Under these agreements, approximately 102 megawatts of capacity is scheduled to be sold annually for periods after 2001 with a minimum of three years notice until the expiration of the contracts in 2010. 8. INCOME TAXES At December 31, 2001, tax-related regulatory assets were $544 million and tax-related regulatory liabilities were $229 million. The assets are II-110 NOTES (continued) Georgia Power Company 2001 Annual Report 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. Details of the federal and state income tax provisions are as follows: 2001 2000 1999 ---------------------------- Total provision for income taxes: (in millions) Federal: Current $352 $342 $333 Deferred (46) (34) (34) -------------------------------------------------------------- 306 308 299 -------------------------------------------------------------- State: Current 61 48 54 Deferred (8) (5) (6) Deferred investment tax credits 5 10 5 -------------------------------------------------------------- Total $364 $361 $352 ============================================================== 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: 2001 2000 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,722 $1,755 Property basis differences 660 683 Other 295 243 ----------------------------------------------------------------- Total 2,677 2,681 ----------------------------------------------------------------- Deferred tax assets: Other property basis differences 178 189 Federal effect of state deferred taxes 88 91 Other deferred costs 257 208 Other 40 37 ----------------------------------------------------------------- Total 563 525 ----------------------------------------------------------------- Net deferred tax liabilities 2,114 2,156 Portion included in current assets 50 27 ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $2,164 $2,183 ================================================================= 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 $15 million in 2001, 2000, and 1999. At December 31, 2001, all investment tax credits available to reduce federal income taxes payable had been utilized. A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows: 2001 2000 1999 ------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 2 2 2 Other (4) (2) (2) -------------------------------------------------------------- Effective income tax rate 37% 39% 39% ============================================================== Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability. 9. CAPITALIZATION First Mortgage Bond Indenture Restrictions The Company's first mortgage bond indenture contains various restrictions that remain in effect as long as the bonds are outstanding. However, the Company expects to discharge its first mortgage bond indenture by spring 2002 and to be released from all indenture requirements. At December 31, 2001, $1.037 billion of retained earnings and paid-in capital was unrestricted for the payment of cash dividends or any other distributions under terms of the mortgage indenture. The Company has no restrictions on the amount of indebtedness it may incur. Preferred Securities Statutory business trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities as follows: Date of Maturity Issue Amount Rate Notes Date --------------------------------------------------- (millions) (millions) Trust I 8/1996 $225.00 7.75% $232 6/2036 Trust II 1/1997 175.00 7.60 180 12/2036 Trust III 6/1997 189.25 7.75 195 3/2037 Trust IV 2/1999 200.00 6.85 206 3/2029 II-111 NOTES (continued) Georgia Power Company 2001 Annual Report Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above. The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with respect to the preferred securities. The Trusts are subsidiaries of the Company, and accordingly are consolidated in the Company's financial statements. Pollution Control Bonds The Company has incurred obligations in connection with the sale by public authorities of tax-exempt pollution control revenue bonds. The Company has authenticated and delivered to trustees an aggregate of $7.8 million of its first mortgage bonds outstanding at December 31, 2001, which are pledged as security for its obligations under pollution control revenue contracts. The redemption of these securities will occur in March 2002. Senior Notes In February 2000, February 2001, and May 2001, the Company issued unsecured senior notes. The proceeds of these issues were used to redeem higher cost long-term debt and to reduce short-term borrowing. The senior notes are, in effect, subordinated to all secured debt of the Company. Bank Credit Arrangements At the beginning of 2002, the Company had unused credit arrangements with banks totaling $1.8 billion, of which $1.3 billion expires at various times during 2002 and $500 million expires at April 24, 2003. Of the total $1.8 billion in unused credit, $1.65 billion is a syndicated credit arrangement with $1.15 billion expiring April 19, 2002 and $500 million expiring April 24, 2003. Upon expiration, the $1.15 billion agreement provides the option of converting borrowings into two-year term loans. Both agreements contain stated borrowing rates but also allow for competitive bid loans. In addition, the agreements require payment of commitment fees based on the unused portions of the commitments. Annual fees are also paid to the agent bank. Approximately $115 million of the $1.3 billion arrangements expiring during 2002 allow for two-year term loans executable upon the expiration date of the facilities. All of the arrangements include stated borrowing rates but also allow for negotiated rates. These agreements also require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. These balances are not legally restricted from withdrawal. This $1.8 billion in unused credit arrangements provides liquidity support to the Company's variable rate pollution control bonds. The amount of variable rate pollution control bonds outstanding requiring that liquidity support as of December 31, 2001 was $984 million. In addition, the Company borrows under uncommitted lines of credit with banks and through commercial paper programs that has the liquidity support of committed bank credit arrangements. Average compensating balances held under these committed facilities were not material in 2001. The amount of commercial paper outstanding at December 31, 2001 was $707.6 million Other Long-Term Debt Assets acquired under capital leases are recorded in the Balance Sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2001 and 2000, the Company had a capitalized lease obligation for its corporate headquarters building of $83 million with an interest rate of 8.1 percent. For ratemaking purposes, the GPSC has treated the lease as an operating lease and has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the GPSC. At December 31, 2001 and 2000, the interest and lease amortization deferred on the Balance Sheets are $54 million and $55 million, respectively. Assets Subject to Lien The Company's mortgage dated as of March 1, 1941, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company's fixed property and franchises. II-112 NOTES (continued) Georgia Power Company 2001 Annual Report Georgia Power expects to discharge its first mortgage bond indenture by spring 2002 and that the lien will be removed. Securities Due Within One Year A summary of the improvement fund requirements and scheduled maturities and redemptions of securities due within one year at December 31 is as follows: 2001 2000 ------------------ (in millions) Capital lease $ 2 $2 First mortgage bonds 2 - Pollution control bonds 8 - Senior notes 300 - --------------------------------------------------------------- Total $312 $2 =============================================================== The Company's first mortgage bond indenture includes an improvement fund requirement that amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to January 1 of each year, other than those issued to collateralize pollution control obligations. The requirement may be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 2/3 times the requirement. However, the Company expects to discharge its first mortgage bond indenture by spring 2002 and to be released from all indenture requirements. Serial maturities through 2006 applicable to total long-term debt are as follows: $312 million in 2002; $352 million in 2003; $2 million in 2004; $154 million in 2005; and $153 million in 2006. 10. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial information for 2001 and 2000 is as follows: Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock --------------------------------------------------------------------- (in millions) -------------------------------------------- March 2001 $1,108 $249 $108 June 2001 1,259 322 163 September 2001 1,579 515 298 December 2001 1,020 126 41 March 2000 $ 992 $223 $ 94 June 2000 1,221 311 148 September 2000 1,545 537 283 December 2000 1,113 162 34 --------------------------------------------------------------------- The Company's business is influenced by seasonal weather conditions. II-113
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 Georgia Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 -------------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands) $4,965,794 $4,870,618 $4,456,675 $4,738,253 $4,385,717 Net Income after Dividends on Preferred Stock (in thousands) $610,335 $559,420 $541,383 $570,228 $593,996 Cash Dividends on Common Stock (in thousands) $527,300 $549,600 $543,000 $536,600 $520,000 Return on Average Common Equity (percent) 14.12 13.66 14.02 14.61 14.53 Total Assets (in thousands) $13,565,941 $13,075,767 $12,361,860 $12,033,618 $12,573,728 Gross Property Additions (in thousands) $1,389,751 $1,078,163 $790,464 $499,053 $475,921 -------------------------------------------------------------------------------------------------------------------------------- Capitalization (in thousands): Common stock equity $4,397,485 $4,249,544 $3,938,210 $3,784,172 $4,019,728 Preferred stock 14,569 14,569 14,952 15,527 157,247 Company obligated mandatorily redeemable preferred securities 789,250 789,250 789,250 689,250 689,250 Long-term debt 2,961,726 3,041,939 2,688,358 2,744,362 2,982,835 -------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) $8,163,030 $8,095,302 $7,430,770 $7,233,311 $7,849,060 ================================================================================================================================ Capitalization Ratios (percent): Common stock equity 53.9 52.5 53.0 52.3 51.2 Preferred stock 0.2 0.2 0.2 0.2 2.0 Company obligated mandatorily redeemable preferred securities 9.6 9.7 10.6 9.5 8.8 Long-term debt 36.3 37.6 36.2 38.0 38.0 -------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 ================================================================================================================================ Security Ratings: First Mortgage Bonds - Moody's A1 A1 A1 A1 A1 Standard and Poor's A A A+ A+ A+ Fitch AA- AA- AA- AA- AA- Preferred Stock - Moody's Baa1 a2 a2 a2 a2 Standard and Poor's BBB+ BBB+ A- A A Fitch A A A+ A+ A+ Unsecured Long-Term Debt - Moody's A2 A2 A2 A2 A2 Standard and Poor's A A A A A Fitch A+ A+ A+ A+ A+ ================================================================================================================================ Customers (year-end): Residential 1,698,407 1,669,566 1,632,450 1,596,488 1,561,675 Commercial 244,674 237,977 229,524 221,180 211,672 Industrial 8,046 8,533 8,958 9,485 9,988 Other 3,239 3,159 3,060 3,034 2,748 -------------------------------------------------------------------------------------------------------------------------------- Total 1,954,366 1,919,235 1,873,992 1,830,187 1,786,083 ================================================================================================================================ Employees (year-end): 9,048 8,860 8,961 8,371 8,354 --------------------------------------------------------------------------------------------------------------------------------
II-114
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued) Georgia Power Company 2001 Annual Report ---------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ---------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands): Residential $ 1,507,031 $1,535,684 $ 1,410,099 $ 1,486,699 $ 1,326,787 Commercial 1,682,918 1,620,466 1,527,880 1,591,363 1,493,353 Industrial 1,106,420 1,154,789 1,143,001 1,170,881 1,110,311 Other 52,943 6,399 (30,892) 49,274 47,848 ---------------------------------------------------------------------------------------------------------------------------- Total retail 4,349,312 4,317,338 4,050,088 4,298,217 3,978,299 Sales for resale - non-affiliates 366,085 297,643 210,104 259,234 282,365 Sales for resale - affiliates 99,411 96,150 76,426 81,606 38,708 ---------------------------------------------------------------------------------------------------------------------------- Total revenues from sales of electricity 4,814,808 4,711,131 4,336,618 4,639,057 4,299,372 Other revenues 150,986 159,487 120,057 99,196 86,345 ---------------------------------------------------------------------------------------------------------------------------- Total $4,965,794 $4,870,618 $4,456,675 $4,738,253 $4,385,717 ============================================================================================================================ Kilowatt-Hour Sales (in thousands): Residential 20,119,080 20,693,481 19,404,709 19,481,486 17,295,022 Commercial 26,493,255 25,628,402 23,715,485 22,861,391 21,134,346 Industrial 25,349,477 27,543,265 27,300,355 27,283,147 26,701,685 Other 583,007 568,906 551,451 543,462 538,163 ---------------------------------------------------------------------------------------------------------------------------- Total retail 72,544,819 74,434,054 70,972,000 70,169,486 65,669,216 Sales for resale - non-affiliates 8,110,096 6,463,723 5,060,931 6,438,891 6,795,300 Sales for resale - affiliates 3,133,485 2,435,106 1,795,243 2,038,400 1,706,699 ---------------------------------------------------------------------------------------------------------------------------- Total 83,788,400 83,332,883 77,828,174 78,646,777 74,171,215 ============================================================================================================================ Average Revenue Per Kilowatt-Hour (cents): Residential 7.49 7.42 7.27 7.63 7.67 Commercial 6.35 6.32 6.44 6.96 7.07 Industrial 4.36 4.19 4.19 4.29 4.16 Total retail 6.00 5.80 5.71 6.13 6.06 Sales for resale 4.14 4.43 4.18 4.02 3.78 Total sales 5.75 5.65 5.57 5.90 5.80 Residential Average Annual Kilowatt-Hour Use Per Customer 11,933 12,520 12,006 12,314 11,171 Residential Average Annual Revenue Per Customer $893.84 $929.11 $872.48 $939.73 $857.01 Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,474 15,114 14,474 14,437 14,437 Maximum Peak-Hour Demand (megawatts): Winter 11,977 12,014 11,568 11,959 10,407 Summer 14,294 14,930 14,575 13,923 13,153 Annual Load Factor (percent) 61.7 61.6 58.9 58.7 57.4 Plant Availability (percent): Fossil-steam 88.5 86.1 84.3 86.0 85.8 Nuclear 94.4 91.5 89.3 91.6 88.8 ---------------------------------------------------------------------------------------------------------------------------- Source of Energy Supply (percent): Coal 58.5 62.3 63.0 62.3 64.3 Nuclear 18.1 17.4 18.0 18.3 18.8 Hydro 1.1 0.7 0.9 2.2 2.2 Oil and gas 0.4 1.8 1.6 2.2 0.6 Purchased power - From non-affiliates 7.8 8.1 6.6 6.5 2.7 From affiliates 14.1 9.7 9.9 8.5 11.4 ---------------------------------------------------------------------------------------------------------------------------- Total 100.0 100.0 100.0 100.0 100.0 ============================================================================================================================ II-115
GULF POWER COMPANY FINANCIAL SECTION II-116 MANAGEMENT'S REPORT Gulf Power Company 2001 Annual Report The management of Gulf Power Company has prepared -- and is responsible for -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements. The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship. The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. The audit committee of the board of directors, composed of five independent directors, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time. Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics. In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Gulf Power Company in conformity with accounting principles generally accepted in the United States. /s/ Travis J. Bowden Travis J. Bowden President and Chief Executive Officer /s/Ronnie R. Labrato Ronnie R. Labrato Vice President, Chief Financial Officer and Comptroller February 13, 2002 II-117 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Gulf Power Company: We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (a Maine corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements (pages II-129 through II-144) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2001, Gulf Power Company changed its method of accounting for derivative instruments and hedging activities. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 II-118 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 2001 Annual Report RESULTS OF OPERATIONS Earnings Gulf Power Company's 2001 net income after dividends on preferred stock was $58.3 million, an increase of $6.5 million from the previous year. In 2000, earnings were $51.8 million, down $1.9 million when compared to 1999. The increase in earnings in 2001 was due primarily to an increase in Allowance for Funds Used During Construction (AFUDC) and lower interest expense; the decrease in 2000 was primarily a result of expenses related to the discontinuance of the Company's appliance sales division, and higher interest expense. Revenues Operating revenues increased in 2001 when compared to 2000. The following table summarizes the change in operating revenues for the past two years: Increase (Decrease) Amount From Prior Year ------------------------------------ 2001 2001 2000 ------------------------------------ (in thousands) Retail -- Base Revenues $340,620 $4,517 $3,771 Regulatory cost recovery and other 243,971 31,434 27,920 ----------------------------------------------------------------- Total retail 584,591 35,951 31,691 ------------------------------------------------------ ---------- Sales for resale-- Non-affiliates 82,252 15,362 4,536 Affiliates 27,256 (39,739) 885 ----------------------------------------------------------------- Total sales for resale 109,508 (24,377) 5,421 Other operating revenues 31,104 (690) 3,108 ----------------------------------------------------------------- Total operating revenues $725,203 $10,884 $40,220 ================================================================= Percent change 1.5% 6.0% ---------------------------------------------------------------- Retail revenues increased $36 million, or 6.6 percent in 2001, and $31.7 million or 6.1 percent in 2000, due primarily to the recovery of higher fuel and purchased power costs. Retail base rate revenues increased $4.5 million due to slightly higher energy sales and lower revenues subject to refund. Revenues subject to refund were $1.5 million in 2001 compared to $6.9 million in 2000. See Note 3 to the financial statements under "Retail Revenue Sharing Plan" for further information. "Regulatory cost recovery and other" includes: recovery provisions for fuel expenses and the energy component of purchased power costs, energy conservation costs, purchased power capacity costs, and environmental compliance costs. Annually, the Company seeks recovery of projected costs plus any true-up amount from prior periods. Approved rates are implemented each January. Therefore, the recovery provisions generally equal the related expenses and have no material effect on net income. See Notes 1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery," respectively, for further information. Sales for resale were $109.5 million in 2001, a decrease of $24.4 million, or 18.2 percent, from 2000 primarily due to reduced energy sales for resale to affiliates. Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components under these long-term contracts were as follows: 2001 2000 1999 ---------------------------------------- (in thousands) Capacity $19,472 $20,270 $19,792 Energy 27,579 21,922 20,251 ------------------------------------------------------------- Total $47,051 $42,192 $40,043 ============================================================= Capacity revenues remained relatively unchanged during 2001 and 2000. Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales have little impact on earnings. Other operating revenues for 2000 increased due primarily to higher franchise fees and higher revenues from the transmission of electricity to others. II-119 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report Energy Sales Kilowatt-hour sales for 2001 and the percent changes by year were as follows: KWH Percent Change -------------------------------- 2001 2001 2000 -------------------------------- (millions) Residential 4,716 (1.5)% 7.1% Commercial 3,418 1.2 4.9 Industrial 2,018 4.8 4.3 Other 21 10.5 0.0 ------------- Total retail 10,173 0.6 5.8 Sales for resale Non-affiliates 2,093 22.8 9.2 Affiliates 963 (49.8) (23.7) ------------- Total 13,229 (3.7) 0.7 ===================================================== Total retail energy sales increased in both 2001 and 2000 primarily due to an increase in the total number of customers. An increase in energy sales for resale to non-affiliates of 22.8 percent in 2001 when compared to 2000 is primarily related to unit power sales under long-term contracts to other Florida utilities and bulk power sales under short-term contracts to other non-affiliated utilities. Energy sales to affiliated companies vary from year to year depending on demand and availability and cost of generating resources at each company. Expenses Total operating expenses in 2001 increased $13.5 million, or 2.3 percent, over the amount recorded in 2000 due primarily to higher purchased power expenses and maintenance expenses. In 2000, total operating expenses increased $39.5 million, or 7.1 percent, compared to 1999 due primarily to higher fuel and purchased power expenses. Fuel expenses in 2001, when compared to 2000, decreased $15.1 million, or 7.0 percent, due primarily to decreased generation, while average fuel costs increased as noted below. In 2000, fuel expenses increased $6.7 million, or 3.2 percent, when compared to 1999. The increase in 2000 was a result of an increase in average fuel costs. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows: 2001 2000 1999 ------------------------------- Total generation (millions of kilowatt-hours) 11,423 12,866 13,095 Sources of generation (percent) Coal 99.0 98.2 97.4 Oil and gas 1.0 1.8 2.6 Average cost of fuel per net kilowatt-hour generated (cents)-- 1.76 1.68 1.60 --------------------------------------------------------------------- Purchased power expenses increased in 2001 by $23.8 million, or 28.8 percent, over 2000 primarily due to an increase in purchased power from affiliate companies. Purchased power expenses for 2000 increased over 1999 by $25.5 million, or 44.7 percent, due primarily to a higher demand for energy. Purchases of energy from affiliates will vary from year to year depending on demand and the availability and cost of generating resources at each company. These purchases have little impact on earnings. Depreciation and amortization expense increased $1.3 million, or 2.0 percent, in 2001, and $2.3 million, or 3.5 percent, in 2000 due to an increase in depreciable property and the amortization of a portion of a regulatory asset, which was allowed in the current retail revenue sharing plan. Other income, net increased in 2001 by $6.8 million compared to 2000 due primarily to higher allowance for equity funds used during construction related to the Company's new combined cycle unit. In 2000, other income, net decreased $2.8 million due primarily to expenses related to the discontinuance of the Company's appliance sales division. See Note 1 to the financial statements under "Other Income" for further information. Interest expense, net decreased $3.1 million, or 10.9 percent, in 2001 due primarily to higher allowance for debt funds used during construction related to the Company's new combined cycle unit, as well as lower interest rates on notes payable and variable rate pollution control bonds. These decreases were partially offset by the issuance of $60 million of senior notes in August 2001 and $75 million of senior notes in October 2001. In 2000, interest expense, net II-120 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report increased $1.2 million, or 4.6 percent, due primarily to the issuance of $50 million of senior notes in August 1999. Effects of Inflation The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its cost of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed. Future Earnings Potential General The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors. The major factor is the ability to achieve energy sales growth while containing costs in a more competitive environment. In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income of approximately $5.9 million in 2001. Future pension income is dependent on several factors including trust earnings and changes to the plan. The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings. The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in northwest Florida. Prices for electricity provided by the Company to retail customers are set by the Florida Public Service Commission (FPSC). Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. Traditionally, these factors have included the rate of economic growth in the Company's service area, weather, competition, changes in contracts with neighboring utilities, the elasticity of demand, and energy conservation practiced by the Company's customers. The Company is actively pursuing additional earnings through unregulated new products and services. In early 1999, the FPSC staff and the Company became involved in discussions primarily related to reducing the Company's authorized rate of return. On October 1, 1999, the Office of Public Counsel, the Coalition for Equitable Rates, the Florida Industrial Power Users Group, and the Company jointly filed a petition to resolve the issues. The stipulation included a reduction to retail base rates of $10 million annually and provides for revenues to be shared within set ranges for 1999 through 2002. Customers receive two-thirds of any revenue within the sharing range and the Company retains one-third. Any revenue above this range is refunded to the customers. The stipulation also included authorization for the Company, at its discretion, to accrue up to an additional $5 million to the property insurance reserve and $1 million to amortize a regulatory asset related to the corporate office. The Company also filed a request to prospectively reduce its authorized return on equity (ROE) range from 11 to 13 percent to 10.5 to 12.5 percent in order to help ensure that the FPSC would approve the stipulation. The FPSC approved both the stipulation and the ROE request with an effective date of November 4, 1999. On September 10, 2001, the Company filed a request with the FPSC for a base rate increase of approximately $70 million, the majority of which is needed to recover costs related to the Smith Unit 3 combined cycle facility currently under construction and scheduled to be placed in service by June 2002. Hearings are scheduled for February 25 through March 1, 2002 with a decision expected in early May 2002 and new rates effective June 6, 2002. For calendar year 2001, the Company's retail revenue range for sharing was $358 million to $374 million. Actual retail revenues in 2001 were $360.3 million and the Company recorded revenues subject to refund of $1.5 million. The estimated refund with interest was reflected in customer billings in February 2002. For calendar year 2002, there are specified sharing ranges for each month from the expected in-service date of Smith Unit 3 until the end of the year. The II-121 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report sharing plan will expire at the earlier of the in-service date of Smith Unit 3 or December 31, 2002. Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters." Also, Florida legislation adopted in 1993 that provides for recovery of prudent environmental compliance costs is discussed in Note 3 to the financial statements under "Environmental Cost Recovery." Industry Restructuring The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it has been a major catalyst for recent restructuring and consolidations taking place within the utility industry. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Florida, none have been enacted. Enactment would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California. As a result of that crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. In 2000, Florida's Governor appointed a 17 member study commission to look at the state's electric industry, studying issues ranging from current and future reliability of electric and natural gas supply, electric industry retail and wholesale competition, environmental impacts of energy supply, conservation, and tax issues. A deadline of December 1, 2001 was set for the commission's final report and recommendations to the Governor and the Legislature. During the course of the study, the Stranded Investment Task Force Subcommittee recommended a discretionary transfer approach regarding the transfer or sale of generation assets by an investor owned utility (IOU). This would allow all new generation to be competitively bid while allowing IOU's to transfer generation units to an affiliate or sell generation units and share proceeds with both shareholders and consumers. Merchants would also be allowed to compete in this restructured wholesale market. This recommendation was approved during the final meeting of the study commission on November 15, 2001 and has been incorporated into the final report. The final report, entitled "Florida...Energy Wise" was presented on December 11, 2001 to the Governor and the Legislature. Any recommendations from the commission will have to be drafted and voted into law by the Legislature. This is unlikely to occur in the upcoming 2002 legislative session. The effects of any proposed changes cannot presently be determined, but could have a material effect on the Company's financial condition and results of operations. Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings. In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In January 2002, the sponsors of SeTrans held a public II-122 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report meeting to form a Stakeholder Advisory Committee, which will participate in the development of the SeTrans RTO. Southern Company continues to work with the other sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to have a material impact on the Company's financial statements. The outcome of this matter cannot now be determined. Accounting Policies Critical Policy Gulf Power Company's significant accounting policies are described in Note 1 to the financial statements. The Company's most critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information. New Accounting Standards Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Statement No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The impact on net income in 2001 was not material. (See Note 1 to the financial statements under "Financial Instruments" for additional information). An additional interpretation of Statement No. 133 will result in a change -- effective April 1, 2002 -- in accounting for certain contracts related to fuel supplies that contain quantity options. These contracts will be accounted for as derivatives and marked to market. However, due to the existence of specific cost-based fuel recovery clauses for the Company, this change is not expected to have a material impact on net income. In June 2001, the FASB issued Statement No. 142, Goodwill and Other Intangible Assets, which establishes new accounting and reporting standards for acquired goodwill and other intangible assets and supersedes Accounting Principles Board Opinion No. 17. Statement No. 142 addresses how intangible assets that are acquired individually or with a group of other assets -- but not those acquired in a business combination -- should be accounted for upon acquisition and on an ongoing basis. Goodwill and intangible assets that have indefinite useful lives will not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives, which are no longer limited to 40 years. The Company adopted Statement No. 142 in January 2002 with no material impact on the financial statements. Also in June 2001, the FASB issued Statement No. 143, Asset Retirement Obligations, which establishes new accounting and reporting standards for legal obligations associated with retiring assets, including decommissioning of nuclear plants. The liability for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The Company has not yet quantified the impact of adopting Statement No. 143 on its financial statements. FINANCIAL CONDITION Overview During 2001, gross property additions were $274.7 million. Funds for the Company's property additions were provided by operating activities and additional financings, which were utilized to finance the construction of the Company's new combined cycle unit. See the Statements of Cash Flows for further details. Credit Rating Risk The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. II-123 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report Exposure to Market Risks Due to cost-based rate regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, similar contracts for gas purchases. Realized gains and losses are recognized in the income statement as incurred. At December 31, 2001, exposure from these activities was not material. Fair value of changes in energy trading contracts and year-end valuations are as follows: Changes During the Year ---------------------------------------------------------------- Fair Value ---------------------------------------------------------------- (in thousands) Contracts beginning of year $110 Contracts realized or settled (100) New contracts at inception - Changes in valuation techniques - Current period changes (120) ---------------------------------------------------------------- Contracts end of year $(110) ================================================================ Source of Year-End Valuation Prices ---------------------------------------------------------------- Maturity Total --------- Fair Value Year 1 1-3 Years ---------------------------------------------------------------- (in thousands) Actively quoted $(110) $(102) $(8) External sources - - - Models and other methods - - - ---------------------------------------------------------------- Contracts end of year $(110) $(102) $(8) ================================================================ If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $0.61 million at December 31, 2001. Financing Activities In 2001, the Company sold $135 million of senior notes and $30 million of trust preferred securities and used the proceeds to retire $30 million of first mortgage bonds and to pay for construction of the Company's new combined cycle unit. In 2000, there were no issuances or retirements of long-term debt. See the Statements of Cash Flows for further details. Composite financing rates for the years 1999 through 2001 as of year end were as follows: 2001 2000 1999 ----------------------------- Composite interest rate on long-term debt 5.6% 6.2% 6.0% Composite rate on trust preferred securities 7.2% 7.3% 7.3% Composite preferred stock dividend rate 5.1% 5.1% 5.1% ----------------------------------------------------------------- The composite interest rate on long-term debt decreased in 2001 due to lower interest rates on variable rate pollution control bonds and lower rates on new senior notes. Capital Requirements for Construction The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $282 million for the three years beginning in 2002 ($103 million in 2002, $72 million in 2003, and $107 million in 2004). These amounts include $24.3 million in 2002 for the remaining cost of a 574 megawatt combined cycle gas generating unit and related interconnections to be located in the eastern portion of the Company's service area. The unit is expected to have an in-service date of June 2002. The remaining property additions budget is primarily for maintaining and upgrading transmission and distribution facilities and generating plants. Actual construction costs may vary from this estimate because of changes in such factors as the following: business conditions; environmental regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Other Capital Requirements The Company will continue to retire higher-cost debt and preferred securities and replace these securities with lower-cost capital as market conditions and terms of the instruments permit. II-124 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report Future note maturities, operating lease obligations, and purchase commitments - discussed in notes 4 and 8 to the financial statements -- are as follows: 2002 2003 2004 -------------------------------------------------------------- (in millions) Bonds - First mortgage $ - $ - $ - Pollution control - - - Notes - 61 51 Leases - Capital - - - Operating 2 2 2 -------------------------------------------------------------- Purchase commitments Fuel 140 109 112 Purchased power 2 1 1 -------------------------------------------------------------- At the beginning of 2002, the Company had not used any of its available credit arrangements. Credit arrangements are as follows: Expires ----------------------------- Total Unused 2002 2003 & beyond -------------------------------------------------------------- (in millions) $103 $103 $103 $ - -------------------------------------------------------------- Environmental Matters In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected the Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995. Southern Company achieved Phase I compliance at the affected plants by primarily switching to low-sulfur coal and with some equipment upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $42 million for the Company. Phase II sulfur dioxide compliance was required in 2000. Southern Company used emission allowances and fuel switching to comply with Phase II requirements. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Phase II compliance did not have a material impact on the Company. A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered. In 1993, the Florida Legislature adopted legislation that allows a utility to petition the FPSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The legislation is discussed in Note 3 to the financial statements under "Environmental Cost Recovery." Substantially all of the costs for the Clean Air Act and other new environmental legislation discussed below are expected to be recovered through the Environmental Cost Recovery Clause. In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals is considering other legal challenges to these standards. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued regional nitrogen oxide reduction rule to the states for implementation. Compliance is required by May 31, 2004 for most states, but for Georgia, further ratemaking is required and compliance may be delayed until May 2005. The final rule affects 21 states, including Georgia, but not Florida. See Note 5 to the financial statements under "Joint Ownership Agreements" related to the Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3. The EPA is presently evaluating whether to bring an additional 15 states, not including Florida, under this regional nitrogen oxide rule. In December 2000, the EPA completed its utility study for mercury and other hazardous air pollutants (HAPS) and issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is to be developed over the next four years under the Maximum Achievable Control Technology provisions of the Clean Air Act, and the regulations are scheduled to be finalized by the end of 2004 with implementation to take place around 2007. In January 2001, the EPA proposed guidance for the determination of Best II-125 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls is expected to take place around 2010. Litigation of the Regional Haze Regulations, including the BART provisions, is ongoing in the Federal District of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002. Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide and reductions in mercury and other HAPS emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. In October 1997, EPA issued regulations setting forth requirements for Compliance Assurance Monitoring (CAM) in its state and federal operating permit programs. These regulations were amended by EPA in March 2001 in response to a court order resolving challenges to the rules brought by environmental groups and industry. Generally, this rule affects the operation and maintenance of electrostatic precipitators and could involve significant additional ongoing expense. The EPA and state environmental regulatory agencies are also reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. On November 3, 1999, the EPA brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, including the five facilities mentioned previously and the Company's Plants Crist and Scherer. For additional information, see Note 5 to the financial statements under "Joint Ownership Agreements" related to the Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add the Company, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court directed the EPA to re-file its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. The EPA re-filed those claims as directed by the court. Also, the EPA re-filed its claims against Alabama Power in U.S. District Court in Alabama. It has not re-filed against the Company, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case could have a significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and Savannah Electric have opposed that motion. The Company believes that it has complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial II-126 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup costs and has recognized in the financial statements costs to clean up known sites. For additional information, see Note 3 to the financial statements under "Environmental Cost Recovery." Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, electric and magnetic fields, and other environmental health concerns could significantly affect the Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electric and magnetic fields. Sources of Capital At December 31, 2001, the Company had approximately $2.2 million of cash and cash equivalents and $2.6 million of unused commercial paper backed by lines of credit with banks to meet its short-term cash needs. See the Statements of Cash Flows for details related to the Company's financing activities. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company operating companies. At December 31, 2001, the Company had outstanding $37.4 million of commercial paper. The Company historically has relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control bonds issued for its benefit by public authorities, to meet its long-term external financing requirements. Recently, the Company's financings have consisted of unsecured debt and trust preferred securities. The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, in order to issue first mortgage bonds or preferred stock, the Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter. The Company's ability to satisfy all coverage requirements is such that it could issue new first mortgage bonds and preferred stock to provide sufficient funds for all anticipated requirements. Cautionary Statement Regarding Forward-Looking Information The Company's 2001 Annual Report contains forward looking and historical information. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential" or "continue" or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental 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, including the pending EPA civil action; the effects, extent, and timing of the entry of additional competition in the markets of the Company; the impact of fluctuations in commodity prices, interest rates and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; the performance of projects undertaken by the non-traditional business and the success of efforts to invest in and develop new opportunities; internal II-127 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2001 Annual Report 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 effects of, and changes in, economic conditions in the Company's service territory; the direct or indirect effects on the Company's business resulting from the terrorist incident on September 11, 2001, or any similar such incidents or responses to such incidents; the timing and acceptance of the Company's new product and services offerings; financial market conditions and the results of financing efforts; weather and other natural phenomena; the ability of the Company to obtain additional generating capacity at competitive prices; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission. 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STATEMENTS OF INCOME For the Years Ended December 31, 2001, 2000, and 1999 Gulf Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------ (in thousands) Operating Revenues: Retail sales $584,591 $548,640 $516,949 Sales for resale -- Non-affiliates 82,252 66,890 62,354 Affiliates 27,256 66,995 66,110 Other revenues 31,104 31,794 28,686 ------------------------------------------------------------------------------------------------------------------ Total operating revenues 725,203 714,319 674,099 ------------------------------------------------------------------------------------------------------------------ Operating Expenses: Operation -- Fuel 200,633 215,744 209,031 Purchased power -- Non-affiliates 65,585 73,846 46,332 Affiliates 40,660 8,644 10,703 Other 117,394 117,146 114,670 Maintenance 60,193 56,281 57,830 Depreciation and amortization 68,218 66,873 64,589 Taxes other than income taxes 55,261 55,904 51,782 ------------------------------------------------------------------------------------------------------------------ Total operating expenses 607,944 594,438 554,937 ------------------------------------------------------------------------------------------------------------------ Operating Income 117,259 119,881 119,162 Other Income (Expense): Interest income 1,258 1,137 1,771 Other, net 2,710 (4,126) (1,357) ------------------------------------------------------------------------------------------------------------------ Earnings Before Interest and Income Taxes 121,227 116,892 119,576 ------------------------------------------------------------------------------------------------------------------ Interest and Other: Interest expense, net 25,034 28,085 26,861 Distributions on preferred securities of subsidiary 6,477 6,200 6,200 ------------------------------------------------------------------------------------------------------------------ Total interest charges and other, net 31,511 34,285 33,061 ------------------------------------------------------------------------------------------------------------------ Earnings Before Income Taxes 89,716 82,607 86,515 Income taxes (Note 7) 31,260 30,530 32,631 ------------------------------------------------------------------------------------------------------------------ Earnings Before Cumulative Effect of 58,456 52,077 53,884 Accounting Change Cumulative effect of accounting change-- less income taxes of $42 thousand 68 - - ------------------------------------------------------------------------------------------------------------------ Net Income 58,524 52,077 53,884 Dividends on Preferred Stock 217 234 217 ------------------------------------------------------------------------------------------------------------------ Net Income After Dividends on Preferred Stock $ 58,307 $ 51,843 $ 53,667 ================================================================================================================== The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001, 2000, and 1999 Gulf Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------ (in thousands) Operating Activities: Net income $ 58,524 $ 52,077 $ 53,884 Adjustments to reconcile net income to net cash provided from operating activities -- Depreciation and amortization 72,320 69,915 68,721 Deferred income taxes, net 3,394 (12,516) (6,609) Other, net (1,804) 10,686 3,735 Changes in certain current assets and liabilities -- Receivables, net 15,991 (20,212) (10,484) Fossil fuel stock (30,887) 13,101 (5,656) Materials and supplies 176 1,055 (2,063) Accounts payable (14,492) 15,924 (2,023) Provision for rate refund 1,530 7,203 - Other (31,249) 12,521 7,030 ------------------------------------------------------------------------------------------------------------------------ Net cash provided from operating activities 73,503 149,754 106,535 ------------------------------------------------------------------------------------------------------------------------ Investing Activities: Gross property additions (274,668) (95,807) (69,798) Other 5,290 (4,432) (8,856) ------------------------------------------------------------------------------------------------------------------------ Net cash used for investing activities (269,378) (100,239) (78,654) ------------------------------------------------------------------------------------------------------------------------ Financing Activities: Increase (decrease) in notes payable, net 44,311 (12,000) 23,500 Proceeds -- Other long-term debt 135,000 - 50,000 Preferred securities 30,000 - - Capital contributions from parent company 72,484 12,222 2,294 Retirements -- First mortgage bonds (30,000) - - Other long-term debt (862) (1,853) (27,074) Preferred stock - - - Payment of preferred stock dividends (217) (234) (271) Payment of common stock dividends (53,275) (59,000) (61,300) Other (3,703) (22) (246) ------------------------------------------------------------------------------------------------------------------------ Net cash provided from (used for) financing activities 193,738 (60,887) (13,097) ------------------------------------------------------------------------------------------------------------------------ Net Change in Cash and Cash Equivalents (2,137) (11,372) 14,784 Cash and Cash Equivalents at Beginning of Period 4,381 15,753 969 ------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at End of Period $ 2,244 $ 4,381 $ 15,753 ======================================================================================================================== Supplemental Cash Flow Information: Cash paid during the period for -- Interest (net of amount capitalized) $30,813 $32,277 $27,670 Income taxes (net of refunds) 33,349 42,252 29,462 ------------------------------------------------------------------------------------------------------------------------ The accompanying notes are an integral part of these statements.
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BALANCE SHEETS At December 31, 2001 and 2000 Gulf Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------- Assets 2001 2000 ------------------------------------------------------------------------------------------------------------- (in thousands) Current Assets: Cash and cash equivalents $ 2,244 $ 4,381 Receivables -- Customer accounts receivable 64,113 69,820 Other accounts and notes receivable 4,316 2,179 Affiliated companies 2,689 15,026 Accumulated provision for uncollectible accounts (1,342) (1,302) Fossil fuel stock, at average cost 47,655 16,768 Materials and supplies, at average cost 28,857 29,033 Regulatory clauses under recovery 24,912 2,112 Other 12,662 6,543 ------------------------------------------------------------------------------------------------------------- Total current assets 186,106 144,560 ------------------------------------------------------------------------------------------------------------- Property, Plant, and Equipment: In service 1,951,512 1,892,023 Less accumulated provision for depreciation 912,581 867,260 ------------------------------------------------------------------------------------------------------------- 1,038,931 1,024,763 Construction work in progress 264,525 71,008 ------------------------------------------------------------------------------------------------------------- Total property, plant, and equipment 1,303,456 1,095,771 ------------------------------------------------------------------------------------------------------------- Other Property and Investments 7,049 4,510 ------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets: Deferred charges related to income taxes (Note 7) 16,766 15,963 Prepaid pension costs (Note 2) 26,364 20,058 Debt expense, being amortized 3,036 2,392 Premium on reacquired debt, being amortized 14,518 15,866 Other 12,222 12,944 ------------------------------------------------------------------------------------------------------------- Total deferred charges and other assets 72,906 67,223 ------------------------------------------------------------------------------------------------------------- Total Assets $1,569,517 $1,312,064 ============================================================================================================= The accompanying notes are an integral part of these balance sheets.
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BALANCE SHEETS At December 31, 2001 and 2000 Gulf Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------- Liabilities and Stockholder's Equity 2001 2000 -------------------------------------------------------------------------------------------------------------- (in thousands) Current Liabilities: Notes payable $ 87,311 $ 43,000 Accounts payable -- Affiliated 18,202 17,558 Other 38,308 38,153 Customer deposits 14,506 13,474 Taxes accrued -- Income taxes 8,162 3,864 Other 8,053 8,749 Interest accrued 8,305 8,324 Provision for rate refund 1,530 7,203 Vacation pay accrued 4,725 4,512 Regulatory clauses over recovery 3,719 6,848 Other 6,528 1,584 -------------------------------------------------------------------------------------------------------------- Total current liabilities 199,349 153,269 -------------------------------------------------------------------------------------------------------------- Long-term debt (See accompanying statements) 467,784 365,993 -------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes (Note 7) 161,968 155,074 Deferred credits related to income taxes (Note 7) 28,293 38,255 Accumulated deferred investment tax credits 24,056 25,792 Employee benefits provisions 37,892 31,075 Other 26,045 25,992 -------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 278,254 276,188 -------------------------------------------------------------------------------------------------------------- Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding company junior subordinated notes (See accompanying statements) 115,000 85,000 -------------------------------------------------------------------------------------------------------------- Preferred stock (See accompanying statements) 4,236 4,236 -------------------------------------------------------------------------------------------------------------- Common stockholder's equity (See accompanying statements) 504,894 427,378 -------------------------------------------------------------------------------------------------------------- Total Liabilities and Stockholder's Equity $1,569,517 $1,312,064 ============================================================================================================== The accompanying notes are an integral part of these balance sheets.
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STATEMENTS OF CAPITALIZATION At December 31, 2001 and 2000 Gulf Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Long Term Debt: First mortgage bonds -- Maturity Interest Rates --------- -------------- July 1, 2003 6.125% $ - $ 30,000 November 1, 2006 6.50% 25,000 25,000 January 1, 2026 6.875% 30,000 30,000 ----------------------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 55,000 85,000 ----------------------------------------------------------------------------------------------------------------------------- Long-term notes payable -- 4.69% due August 1, 2003 60,000 - 7.05% due August 15, 2004 50,000 50,000 6.10% due September 30, 2016 75,000 - 7.50% due June 30, 2037 20,000 20,000 6.70% due June 30, 2038 47,211 48,073 ----------------------------------------------------------------------------------------------------------------------------- Total long-term notes payable 252,211 118,073 ----------------------------------------------------------------------------------------------------------------------------- Other long-term debt -- Pollution control revenue bonds -- Collateralized: 5.25% to 6.30% due 2006-2026 108,700 108,700 Non-collateralized: Variable rates (1.75% to 1.95% at 1/1/02) due 2022-2024 60,930 60,930 ----------------------------------------------------------------------------------------------------------------------------- Total other long-term debt 169,630 169,630 ----------------------------------------------------------------------------------------------------------------------------- Unamortized debt premium (discount), net (9,057) (6,710) ----------------------------------------------------------------------------------------------------------------------------- Total long-term debt (annual interest requirement -- $29.2 million) 467,784 365,993 42.9% 41.5% ----------------------------------------------------------------------------------------------------------------------------- Cumulative Preferred Stock: $100 par value, 4.64% to 5.44% 4,236 4,236 ----------------------------------------------------------------------------------------------------------------------------- Total (annual dividend requirement -- $0.2 million) 4,236 4,236 0.4% 0.5% ----------------------------------------------------------------------------------------------------------------------------- Company Obligated Mandatorily Redeemable Preferred Securities: $25 liquidation value -- 7.00% 45,000 45,000 7.38% 30,000 - 7.63% 40,000 40,000 ----------------------------------------------------------------------------------------------------------------------------- Total (annual distribution requirement -- $8.4 million) 115,000 85,000 10.5% 9.6% ----------------------------------------------------------------------------------------------------------------------------- Common Stockholder's Equity: Common stock, without par value -- Authorized and outstanding - 992,717 shares in 2001 and 2000 38,060 38,060 Paid-in capital 305,960 233,476 Premium on preferred stock 12 12 Retained earnings 160,862 155,830 ----------------------------------------------------------------------------------------------------------------------------- Total common stockholder's equity 504,894 427,378 46.2% 48.4% ----------------------------------------------------------------------------------------------------------------------------- Total Capitalization $1,091,914 $882,607 100.0% 100.0% ============================================================================================================================= The accompanying notes are an integral part of these statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2001, 2000, and 1999 Gulf Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------- Premium on Common Paid-In Preferred Retained Stock Capital Stock Earnings Total ----------------------------------------------------------------------------------------------------------------------------- (in thousands) Balance at January 1, 1999 $38,060 $218,960 $12 $170,620 $427,652 Net income after dividends on preferred stock - - - 53,667 53,667 Capital contributions from parent company - 2,294 - - 2,294 Cash dividends on common stock - - - (51,300) (51,300) Other - - - (10,000) (10,000) ----------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 38,060 221,254 12 162,987 422,313 Net income after dividends on preferred stock - - - 51,843 51,843 Capital contributions from parent company - 12,222 - - 12,222 Cash dividends on common stock - - - (59,000) (59,000) Balance at December 31, 2000 38,060 233,476 12 155,830 427,378 ----------------------------------------------------------------------------------------------------------------------------- Net income after dividends on preferred stock - - - 58,307 58,307 Capital contributions from parent company - 72,484 - - 72,484 Cash dividends on common stock - - - (53,275) (53,275) ----------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 $38,060 $305,960 $12 $160,862 $504,894 ============================================================================================================================= The accompanying notes are an integral part of these statements.
II-134 NOTES TO FINANCIAL STATEMENTS Gulf Power Company 2001 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Gulf Power Company (Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company (SCS), Southern Communications Services (Southern LINC), Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern Power), and other direct and indirect subsidiaries. The operating companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four southeastern states. Contracts among the operating companies -- related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Florida Public Service Commission (FPSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by the FPSC and the FERC. 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. Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation. Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension 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 $45 million, $44 million, and $43 million during 2001, 2000, and 1999, respectively. Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following: 2001 2000 -------------------------- (in thousands) Deferred income tax charges $ 16,766 $ 15,963 Deferred loss on reacquired debt 14,518 15,866 Environmental remediation 7,163 7,638 Vacation pay 4,725 4,512 Accumulated provision for rate refunds (1,530) (7,203) Accumulated provision for property damage (13,565) (8,731) Deferred income tax credits (28,293) (38,255) Other, net (1,443) (1,074) ------------------------------------------------------------------ Total $ (1,659) $(11,284) ================================================================== In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value. II-135 NOTES (continued) Gulf Power Company 2001 Annual Report Revenues and Regulatory Cost Recovery Clauses The Company currently operates as a vertically integrated utility providing electricity to retail customers within its service area located in northwest Florida and to wholesale customers in the Southeast. Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The Company's retail electric rates include provisions to annually adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company also has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted monthly for differences between recoverable costs and amounts actually reflected in current rates. The Company has a diversified base of customers and no single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged significantly less than 1 percent of revenues. Depreciation and Amortization Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.7 percent in 2001 and 3.8 percent in both 2000, and 1999. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -- together with the cost of removal, less salvage -- is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Also, the provision for depreciation expense includes an amount for the expected cost of removal of facilities. Other Income Other income consists principally of interest and dividend income, Allowance for Funds Used During Construction (AFUDC)-equity, and income or expenses on other non-regulated activities. In 2000 and 1999, the non-regulated activities included the results of the Company's merchandising operations, which were discontinued in the latter part of 2000. Income Taxes The Company uses the liability method of accounting for income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. Cash and Cash Equivalents Temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Financial Instruments Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The impact on net income was immaterial. II-136 NOTES (continued) Gulf Power Company 2001 Annual Report The Company uses derivative financial instruments to hedge exposures to fluctuations in interest rates, and certain commodity prices. Gains and losses on qualifying hedges are deferred and recognized either in income or as an adjustment to the carrying amount of the hedged item when the transaction occurs. The Company 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 and its affiliates, through SCS acting as their agent, enters into commodity related forward and option contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of the Company's bulk energy purchases and sales contracts meet the definition of a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. In many cases, these fuel and electricity contracts qualify for normal purchase and sale exceptions under Statement No. 133 and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses, and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income. Other financial instruments for which the carrying amount did not equal fair value at December 31 were as follows: Carrying Fair Amount Value --------------------------- (in thousands) Long-term debt: At December 31, 2001 $467,784 $474,911 At December 31, 2000 $365,993 $364,697 Capital trust preferred securities: At December 31, 2001 $115,000 $114,898 At December 31, 2000 $85,000 $80,988 -------------------------------------------------------------- The fair values for long-term debt and preferred securities were based on either closing market prices or closing prices of comparable instruments. Materials and Supplies Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Provision for Injuries and Damages The Company is subject to claims and suits arising in the ordinary course of business. As permitted by regulatory authorities, the Company provides for the uninsured costs of injuries and damages by charges to income amounting to $1.2 million annually. The expense of settling claims is charged to the provision to the extent available. The accumulated provision of $1.3 million and $1.2 million at December 31, 2001 and 2000, respectively, is included in other current liabilities in the accompanying Balance Sheets. Provision for Property Damage The Company provides for the cost of repairing damages from major storms and other uninsured property damages. This includes the full cost of major storms and other damages to its transmission and distribution lines and the cost of uninsured damages to its generation and other property. The expense of such damages is charged to the provision account. At December 31, 2001 and 2000, the accumulated provision for property damage was $13.6 million and $8.7 million, respectively. The FPSC approved annual accrual to the accumulated provision for property damage is $3.5 million, with a target level for the accumulated provision account between $25.1 and $36.0 million. The FPSC has also given the Company the flexibility to increase its annual accrual amount above $3.5 million at the Company's discretion. The Company accrued $4.5 million in 2001, $3.5 million in 2000, and $5.5 million in 1999 to the accumulated provision for property damage. The Company had a net credit of $(0.3) million to the provision account in 2001 related to insurance proceeds that exceeded actual claims. In 2000 and 1999, the Company charged $0.3 million and $1.6 million, respectively, to the provision account. 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits when they retire. Trusts are II-137 NOTES (continued) Gulf Power Company 2001 Annual Report funded to the extent required by the Company's regulatory commissions. In late 2000, the Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees. The measurement date for plan assets and obligations is September 30 for each year. Pension Plan Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations --------------------------- 2001 2000 --------------------------------------------------------------- (in thousands) Balance at beginning of year $153,214 $146,106 Service cost 4,703 4,367 Interest cost 11,644 10,695 Benefits paid (8,105) (7,169) Actuarial gain and employee transfers, net (195) (785) Amendments 7,997 - Other (7) - --------------------------------------------------------------- Balance at end of year $169,251 $153,214 =============================================================== Plan Assets -------------------------- 2001 2000 --------------------------------------------------------------- (in thousands) Balance at beginning of year $283,266 $241,485 Actual return on plan assets (40,841) 43,833 Benefits paid (7,758) (6,973) Employee transfers (961) 4,921 --------------------------------------------------------------- Balance at end of year $233,706 $283,266 =============================================================== The accrued pension costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------- (in thousands) Funded status $ 64,455 $ 130,052 Unrecognized transition obligation (2,832) (3,503) Unrecognized prior service cost 11,689 4,529 Unrecognized net gain (47,038) (111,092) 4th quarter cash flow adjustment 90 72 --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 26,364 $20,058 =============================================================== Components of the pension plan's net periodic cost were as follows: 2001 2000 1999 ------------------------------------------------------------------- Service cost $ 4,703 $ 4,367 $ 4,556 Interest cost 11,644 10,695 9,729 Expected return on plan assets (19,312) (17,504) (15,968) Recognized net gain (3,072) (2,582) (234) Net amortization 165 (235) (1,549) ------------------------------------------------------------------- Net pension income $ (5,872) $ (5,259) $ (3,466) =================================================================== Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations --------------------------- 2001 2000 --------------------------------------------------------------- (in thousands) Balance at beginning of year $50,025 $48,010 Service cost 983 896 Interest cost 3,886 3,515 Benefits paid (1,823) (1,462) Amendments 3,412 - --------------------------------------------------------------- Actuarial gain (2,146) (934) --------------------------------------------------------------- Balance at end of year $54,337 $50,025 =============================================================== Plan Assets --------------------------- 2001 2000 --------------------------------------------------------------- (in thousands) Balance at beginning of year $13,388 $11,196 Actual return on plan assets (1,830) 2,079 Employer contributions 1,897 1,575 Benefits paid (1,823) (1,462) --------------------------------------------------------------- Balance at end of year $11,632 $13,388 =============================================================== The accrued postretirement costs recognized in the Balance Sheets were as follows: 2001 2000 ---------------------------------------------------------------- (in thousands) Funded status $(42,705) $(36,638) Unrecognized transition obligation 4,012 4,368 Unrecognized prior service cost 5,695 2,582 Unrecognized net loss 1,235 496 Fourth quarter contributions 386 316 ---------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(31,377) $(28,876) ================================================================ II-138 NOTES (continued) Gulf Power Company 2001 Annual Report Components of the postretirement plan's net periodic cost were as follows: 2001 2000 1999 ----------------------------------------------------------------- Service cost $ 983 $ 896 $ 1,087 Interest cost 3,886 3,515 3,261 Expected return on plan assets (1,037) (901) (794) Transition obligation 356 355 356 Prior service cost 299 159 159 Recognized net (gain)/loss (18) 13 264 ----------------------------------------------------------------- Net post-retirement cost $ 4,469 $ 4,037 $ 4,333 ================================================================= The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits plan were: 2001 2000 ---------------------------------------------------------- Discount 7.50% 7.50% Annual salary increase 5.00% 5.00% Long-term return on plan assets 8.50% 8.50% ---------------------------------------------------------- An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 9.25 percent for 2001, decreasing gradually to 5.25 percent through the year 2010, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2001 as follows (in thousands): 1 Percent 1 Percent Increase Decrease --------------------------------------------------------------- Benefit obligation $4,575 $3,985 Service and interest costs $410 $351 =============================================================== Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2001, 2000, and 1999 were $2.3 million, $2.2 million, and $2.0 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General The Company is subject to certain claims and legal actions arising in the ordinary course of business. In the opinion of management, after consultation with legal counsel, the ultimate disposition of these matters is not expected to have a material adverse effect on the Company's financial condition. Environmental Cost Recovery In 1993, the Florida Legislature adopted legislation for an Environmental Cost Recovery Clause (ECRC), which allows a utility to petition the FPSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operation and maintenance expense, emission allowance expense, depreciation, and a return on invested capital. In 1994, the FPSC approved the Company's initial petition under the ECRC for recovery of environmental costs. During 2001, 2000, and 1999, the Company recorded ECRC revenues of $10.0 million, $9.9 million, and $11.5 million, respectively. At December 31, 2001, the Company's liability for the estimated costs of environmental remediation projects for known sites was $7.2 million. These estimated costs are expected to be expended from 2002 through 2008. These projects have been approved by the FPSC for recovery through the ECRC discussed above. Therefore, the Company recorded $1.2 million in current assets and current liabilities and $6.0 million in deferred assets and deferred liabilities representing the future recoverability of these costs. Environmental Litigation On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and SCS. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action II-139 NOTES (continued) Gulf Power Company 2001 Annual Report requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, including the five facilities mentioned previously and the Company's Plants Crist and Scherer. See Note 5 under "Joint Ownership Agreements" related to the Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add the Company, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. On August 1, 2000, the U.S. District Court granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted SCS's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court directed the EPA to re-file its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. The EPA re-filed those claims as directed by the court. Also, the EPA re-filed its claims against Alabama Power in U.S. District Court in Alabama. It has not re-filed against the Company, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case could have a significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and Savannah Electric have opposed that motion. The Company believes that it has complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. Retail Revenue Sharing Plan In early 1999, the FPSC staff and the Company became involved in discussions primarily related to reducing the Company's authorized rate of return. On October 1, 1999, the Office of Public Counsel, the Coalition for Equitable Rates, the Florida Industrial Power Users Group, and the Company jointly filed a petition to resolve the issues. The stipulation included a reduction to retail base rates of $10 million annually and provided for revenues to be shared within set ranges for 1999 through 2002. Customers receive two-thirds of any revenue within the sharing range and the Company retains one-third. Any revenue above this range is refunded to the customers. The stipulation also included authorization for the Company, at its discretion, to accrue up to an additional $5 million to the property insurance reserve and $1 million to amortize a regulatory asset related to the corporate office. The Company also filed a request to prospectively reduce its authorized return on equity (ROE) range from 11 to 13 percent to 10.5 to 12.5 percent in order to help ensure that the FPSC would approve the stipulation. The FPSC approved both the stipulation and the ROE request with an effective date of November 4, 1999. The Company's retail revenue range for sharing was $358 million to $374 million in calendar year 2001, and $352 million to $368 million in 2000, to be shared between the Company and its retail customers on the one-third/two-thirds basis. Actual retail revenues in 2001 were $360.3 million and $362.4 million in 2000. The Company recorded revenues subject to refund of $1.5 million in 2001 and $6.9 million in 2000. The estimated refund with interest was $0.03 million in 2001 and $0.3 million in 2000 and was reflected in customer billings in February 2002 and 2001 respectively. In addition to the refund, the Company amortized $1 million of the regulatory assets related to the corporate office in 2001 and 2000, and accrued an additional $1.0 million to the property insurance II-140 NOTES (continued) Gulf Power Company 2001 Annual Report reserve in 2001. For calendar year 2002, there are specified sharing ranges for each month from the expected in-service date of Smith Unit 3 until the end of the year. The sharing plan will expire at the earlier of the in-service date of Smith Unit 3 or December 31, 2002. Retail Rate Case On September 10, 2001, the Company filed a request with the FPSC for a base rate increase of approximately $70 million, the majority of which is needed to recover costs related to the Smith Unit 3 combined cycle facility currently under construction and scheduled to be placed in service by June 2002. Hearings are scheduled for February 25 through March 1, 2002 with a decision expected in early May 2002 and new rates effective June 6, 2002. 4. COMMITMENTS Construction Program The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $103 million in 2002, $72 million in 2003, and $107 million in 2004. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; revised load growth estimates; changes in environmental regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2001, significant purchase commitments were outstanding in connection with the construction program. The Company has budgeted $24.3 million in 2002 as the remaining cost of a 574 megawatt combined cycle gas generating unit to be located in the eastern portion of its service area. The unit is expected to have an in-service date of June 2002. The Company's remaining construction program is related to maintaining and upgrading the transmission, distribution, and generating facilities. Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into contract commitments for the procurement of fuel. In some cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Total estimated obligations at December 31, 2001 were as follows: Year Fuel --------- ---------------- (in millions) 2002 $140 2003 109 2004 112 2005 113 2006 115 2007-2025 398 ---------------------------------------------------------- Total commitments $987 ========================================================== In addition, SCS acts as agent for the five operating companies and Southern Power with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes are allocated based on usage projections as of December 31 as follows: Year Natural Gas --------- ---------------- (MMBtu) 2002 14,194,988 2003 28,377,592 2004 15,071,438 2005 6,913,093 2006 4,187,658 2007 and thereafter 1,676,250 ------------------------------------------------------ Total commitments 70,421,019 ====================================================== Additional commitments for fuel will be required in the future to supply the Company's fuel needs. Lease Agreements In 1989, the Company and Mississippi Power jointly entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars. In 1994, a second lease agreement for the use of 250 additional aluminum railcars was entered into for twenty-two years. Both of these leases are for the transportation of coal to Plant Daniel. At the end of each lease term, the Company has the option to purchase the 745 railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. II-141 NOTES (continued) Gulf Power Company 2001 Annual Report The Company, as a joint owner of Plant Daniel, is responsible for one half of the lease costs. The lease costs are charged to fuel inventory and are allocated to fuel expense as the fuel is used. The Company's share of the lease costs charged to fuel inventories was $1.9 million in 2001 and $2.4 million in 2000. The annual amounts for 2002 through 2006 are expected to be $1.9 million, $1.9 million, $1.9 million, $2.0 million, and $2.0 million, respectively, and after 2006 are expected to total $11.7 million. 5. JOINT OWNERSHIP AGREEMENTS The Company and Mississippi Power jointly own Plant Daniel Unit No. 1 and Unit No. 2. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of these units. The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit. The Company's pro rata share of expenses related to both plants is included in the corresponding operating expense accounts in the Statements of Income. At December 31, 2001, the Company's percentage ownership and its investment in these jointly owned facilities were as follows: Plant Plant Scherer Daniel Unit Unit No. 3 Nos. 1 & 2 (coal-fired) (coal-fired) ----------------------------- (in thousands) Plant In Service $184,901(1) $228,278 Accumulated Depreciation $73,684 $120,646 Construction Work in Progress $1,556 $6,174 Nameplate Capacity (2) (megawatts) 205 500 Ownership 25% 50% ------------------------------------------------------------------ (1) Includes net plant acquisition adjustment. (2) Total megawatt nameplate capacity: Plant Scherer Unit No. 3: 818 Plant Daniel Unit Nos. 1&2: 1,000 6. LONG-TERM POWER SALES AGREEMENTS The Company and the other operating affiliates have long-term contractual agreements for the sale of capacity to certain non-affiliated utilities located outside the system's service area. The unit power sales agreements are firm and pertain to capacity related to specific generating units. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The capacity revenues from these sales were $19.5 million in 2001, $20.3 million in 2000, and $19.8 million in 1999. Unit power from specific generating plants of Southern Company is currently being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority (JEA). Under these agreements, 210 megawatts of net dependable capacity were sold by the Company during 2001. Sales will remain close to that level, unless reduced by FP&L, FPC, and JEA with a minimum of three years notice, until the expiration of the contracts in 2010. 7. INCOME TAXES At December 31, 2001, the tax-related regulatory assets to be recovered from customers were $16.8 million. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized allowance for funds used during construction. At December 31, 2001, the tax-related regulatory liabilities to be credited to customers were $28.3 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Details of the federal and state income tax provisions are as follows: 2001 2000 1999 ---------------------------------- (in thousands) Total provision for income taxes: Federal-- Current $24,207 $37,250 $33,973 Deferred 2,568 (11,159) (6,107) 26,775 26,091 27,866 ------------------------------------------------------------------ State-- Current 3,701 5,796 5,267 Deferred 826 (1,357) (502) 4,527 4,439 4,765 ------------------------------------------------------------------ Total $31,302 $30,530 $32,631 ================================================================== II-142 NOTES (continued) Gulf Power Company 2001 Annual Report The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2001 2000 --------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $179,071 $172,646 Other 27,328 14,262 --------------------------------------------------------------------- Total 206,399 186,908 --------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 9,009 8,703 Postretirement benefits 9,379 9,205 Other 17,881 14,742 --------------------------------------------------------------------- Total 36,269 32,650 --------------------------------------------------------------------- Net deferred tax liabilities 170,130 154,258 Less current portion, net (8,162) (816) --------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $161,968 $155,074 ===================================================================== Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation and amortization in the Statements of Income. Credits amortized in this manner amounted to $1.7 million in 2001 and $1.9 million in each of 2000 and 1999. At December 31, 2001, all investment tax credits available to reduce federal income taxes payable had been utilized. A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2001 2000 1999 --------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 1 1 1 Difference in prior years' deferred and current tax rate (2) (2) (2) Other, net (3) (1) - --------------------------------------------------------------- Effective income tax rate 35% 37% 38% =============================================================== The Company and the other subsidiaries of Southern Company file a consolidated federal tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability. 8. CAPITALIZATION Preferred Securities In January 1997, Gulf Power Capital Trust I (Trust I), of which the Company owns all of the common securities, issued $40 million of 7.625 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust I are $41 million aggregate principal amount of the Company's 7.625 percent junior subordinated notes due December 31, 2036. In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company owns all of the common securities, issued $45 million of 7.0 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust II are $46 million aggregate principal amount of the Company's 7.0 percent junior subordinated notes due December 31, 2037. In November 2001, Gulf Power Capital Trust III (Trust III), of which the Company owns all of the common securities, issued $30 million of 7.375 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust III are $31 million aggregate principal amount of the Company's 7.375 percent junior subordinated notes due September 30, 2041. The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of payment obligations with respect to the preferred securities of Trust I, Trust II, and Trust III. Trust I, Trust II, and Trust III are subsidiaries of the Company, and accordingly are consolidated in the Company's financial statements. Securities Due Within One Year At December 31, 2001, the Company had an improvement fund requirement of $550,000. The first mortgage bond improvement fund requirement amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to January 1 of each year, other than those issued to collateralize pollution control revenue bond obligations. The requirement may be satisfied by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 and 2/3 times the requirement. The sinking fund requirements of first mortgage bonds were satisfied by certifying property additions in 2001 and 2000. It is anticipated that the 2002 II-143 NOTES (continued) Gulf Power Company 2001 Annual Report requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2006 applicable to long-term debt are as follows: none in 2002; $60.6 million in 2003; $50.6 million on 2004; none in 2005; and $37.6 million in 2006. Dividend Restrictions The Company's first mortgage bond indenture contains various common stock dividend restrictions, which remain in effect as long as the bonds are outstanding. At December 31, 2001, retained earnings of $127 million were restricted against the payment of cash dividends on common stock under the terms of the mortgage indenture. Bank Credit Arrangements At December 31, 2001, the Company had $41.5 million of lines of credit with banks subject to renewal June 1 of each year, of which $41.5 million remained unused. In addition, the Company has two unused committed lines of credit totaling $61.9 million that were established for liquidity support of its variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees and/or to maintain compensating balances with the banks. The compensating balances, which represent substantially all of the cash of the Company except for daily working funds and like items, are not legally restricted from withdrawal. The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the Company from time to time borrows under uncommitted lines of credit with banks. The amount of commercial paper outstanding at December 31, 2001 was $37.4 million. In addition, the Company has bid-loan facilities with five major money center banks that total $110 million, of which $50 million was committed at December 31, 2001. Assets Subject to Lien The Company's mortgage, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises. 9. QUARTERLY FINANCIAL DATA (Unaudited) Summarized quarterly financial data for 2001 and 2000 are as follows: Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock -------------------------------------------------------------------- (in thousands) March 2001 $165,029 $24,785 $10,196 June 2001 180,430 30,702 14,770 September 2001 226,616 45,504 26,657 December 2001 153,128 16,268 6,684 March 2000 $138,498 $16,007 $4,653 June 2000 182,120 30,505 12,927 September 2000 232,533 52,614 26,438 December 2000 161,168 20,755 7,825 -------------------------------------------------------------------- The Company's business is influenced by seasonal weather conditions and the timing of rate changes, among other factors. II-144
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 Gulf Power Company 2001 Annual Report --------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 --------------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands) $725,203 $714,319 $674,099 $650,518 $625,856 Net Income after Dividends on Preferred Stock (in thousands) $58,307 $51,843 $53,667 $56,521 $57,610 Cash Dividends on Common Stock (in thousands) $53,275 $59,000 $61,300 $57,200 $64,600 Return on Average Common Equity (percent) 12.51 12.20 12.63 13.20 13.33 Total Assets (in thousands) $1,569,517 $1,312,064 $1,308,495 $1,267,901 $1,265,612 Gross Property Additions (in thousands) $274,668 $95,807 $69,798 $69,731 $54,289 --------------------------------------------------------------------------------------------------------------------------------- Capitalization (in thousands): Common stock equity $504,894 $427,378 $422,313 $427,652 $428,718 Preferred stock 4,236 4,236 4,236 4,236 13,691 Company obligated mandatorily redeemable preferred securities 115,000 85,000 85,000 85,000 40,000 Long-term debt 467,784 365,993 367,449 317,341 296,993 --------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) $1,091,914 $882,607 $878,998 $834,229 $779,402 ================================================================================================================================= Capitalization Ratios (percent): Common stock equity 46.2 48.4 48.0 51.3 55.0 Preferred stock 0.4 0.5 0.5 0.5 1.8 Company obligated mandatorily redeemable preferred securities 10.5 9.6 9.7 10.2 5.1 Long-term debt 42.9 41.5 41.8 38.0 38.1 --------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 ================================================================================================================================= Security Ratings: First Mortgage Bonds - Moody's A1 A1 A1 A1 A1 Standard and Poor's A+ A+ AA- AA- AA- Fitch A+ AA- AA- AA- AA- Preferred Stock - Moody's Baa1 a2 a2 a2 a2 Standard and Poor's BBB+ BBB+ A- A A 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 327,128 321,731 315,240 307,077 300,257 Commercial 48,654 47,666 47,728 46,370 44,589 Industrial 270 280 267 257 267 Other 468 442 316 268 264 --------------------------------------------------------------------------------------------------------------------------------- Total 376,520 370,119 363,551 353,972 345,377 ================================================================================================================================= Employees (year-end): 1,309 1,327 1,339 1,328 1,328 ---------------------------------------------------------------------------------------------------------------------------------
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SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued) Gulf Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 -------------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands): Residential $ 313,165 $302,210 $ 279,238 $ 279,621 $ 276,924 Commercial 188,759 177,047 167,305 163,207 163,751 Industrial 81,719 74,095 68,222 71,119 77,045 Other 948 (4,712) 2,184 2,113 2,077 -------------------------------------------------------------------------------------------------------------------------------- Total retail 584,591 548,640 516,949 516,060 519,797 Sales for resale - non-affiliates 82,252 66,890 62,354 61,893 63,697 Sales for resale - affiliates 27,256 66,995 66,110 42,642 16,760 -------------------------------------------------------------------------------------------------------------------------------- Total revenues from sales of electricity 694,099 682,525 645,413 620,595 600,254 Other revenues 31,104 31,794 28,686 29,923 25,602 -------------------------------------------------------------------------------------------------------------------------------- Total $725,203 $714,319 $674,099 $650,518 $625,856 ================================================================================================================================ Kilowatt-Hour Sales (in thousands): Residential 4,716,404 4,790,038 4,471,118 4,437,558 4,119,492 Commercial 3,417,427 3,379,449 3,222,532 3,111,933 2,897,887 Industrial 2,018,206 1,924,749 1,846,237 1,833,575 1,903,050 Other 21,208 18,730 19,296 18,952 18,101 -------------------------------------------------------------------------------------------------------------------------------- Total retail 10,173,245 10,112,966 9,559,183 9,402,018 8,938,530 Sales for resale - non-affiliates 2,093,203 1,705,486 1,561,972 1,341,990 1,531,179 Sales for resale - affiliates 962,892 1,916,526 2,511,983 1,758,150 848,135 -------------------------------------------------------------------------------------------------------------------------------- Total 13,229,340 13,734,978 13,633,138 12,502,158 11,317,844 ================================================================================================================================ Average Revenue Per Kilowatt-Hour (cents): Residential 6.64 6.31 6.25 6.30 6.72 Commercial 5.52 5.24 5.19 5.24 5.65 Industrial 4.05 3.85 3.70 3.88 4.05 Total retail 5.75 5.43 5.41 5.49 5.82 Sales for resale 3.58 3.70 3.15 3.37 3.38 Total sales 5.25 4.97 4.73 4.96 5.30 Residential Average Annual Kilowatt-Hour Use Per Customer 14,497 14,992 14,318 14,577 13,894 Residential Average Annual Revenue Per Customer $962.57 $945.87 $894.18 $918.56 $933.99 Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,188 2,188 2,188 2,188 2,174 Maximum Peak-Hour Demand (megawatts): Winter 2,106 2,154 2,085 2,040 1,844 Summer 2,223 2,285 2,161 2,146 2,032 Annual Load Factor (percent) 57.5 55.4 55.2 55.3 55.5 Plant Availability Fossil-Steam (percent): 90.1 85.2 87.2 87.6 91.0 -------------------------------------------------------------------------------------------------------------------------------- Source of Energy Supply (percent): Coal 81.2 87.8 89.8 89.2 87.1 Oil and gas 1.0 1.6 2.5 2.0 0.4 Purchased power - From non-affiliates 6.5 7.6 5.9 5.5 3.5 From affiliates 11.3 3.0 1.8 3.3 9.0 -------------------------------------------------------------------------------------------------------------------------------- Total 100.0 100.0 100.0 100.0 100.0 ================================================================================================================================
II-146 MISSISSIPPI POWER COMPANY FINANCIAL SECTION II-147 MANAGEMENT'S REPORT Mississippi Power Company 2001 Annual Report The management of Mississippi Power Company has prepared -- and is responsible for -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements. The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship. The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. The audit committee of the board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time. Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics. In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Mississippi Power Company in conformity with accounting principles generally accepted in the United States. /s/Michael D. Garrett Michael D. Garrett President and Chief Executive Officer /s/Michael W. Southern Michael W. Southern Vice President, Treasurer and Chief Financial Officer February 13, 2002 II-148 REPORT OF INDEPENDENT PUBLIC ACCOUNTANT To Mississippi Power Company: We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (a Mississippi corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements (pages II-160 through II-176) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2001, Mississippi Power Company changed its method of accounting for derivative instruments and hedging activities. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 II-149 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 2001 Annual Report RESULTS OF OPERATIONS Earnings Mississippi Power Company's 2001 net income after dividends on preferred stock of $63.9 million increased $8.9 million over 2000 earnings of $55.0 million, which were $0.2 million more than 1999 earnings of $54.8 million. Net income for 2001 was higher due to additional sales for resale primarily attributable to the commercial operation of the new Plant Daniel Combined Cycle Units 3 and 4 and lower interest expense. Revenues Operating revenues for the Company in 2001 and the changes from the prior year are as follows: Increase (Decrease) Amount From Prior Year ------ ---------------- 2001 2001 2000 --------------------------------------- (in thousands) Retail -- Base Revenues $284,255 $ (3,000) $ (4,343) Fuel cost recovery and other 204,898 (6,398) 33,460 ----------------------------------------------------------------- Total retail 489,153 (9,398) 29,117 ----------------------------------------------------------------- Sales for resale -- Non-affiliates 204,623 58,692 14,927 Affiliates 85,652 57,737 8,469 ----------------------------------------------------------------- Total sales for resale 290,275 116,429 23,396 Other operating revenues 16,637 1,432 2,085 ----------------------------------------------------------------- Operating revenues $796,065 $108,463 $ 54,598 ================================================================= Percent change 15.8% 8.6% ----------------------------------------------------------------- Total retail revenues for 2001 decreased approximately 1.9 percent when compared to 2000. The decrease resulted primarily from lower energy sales to residential, commercial, and industrial customers as a result of mild weather and a slowdown in manufacturing activity in the Company's service territory. Retail revenues for 2000 reflected a 6.2 percent increase over the prior year due to the continued growth in the service area, increased fuel revenues, and a positive weather impact. Fuel revenues generally represent the direct recovery of fuel expense including purchased power. Therefore, changes in recoverable fuel expenses are offset with corresponding changes in fuel revenues and have no effect on net income. Sales for resale to non-affiliates are influenced by those utilities' own customer demand, plant availability, and the cost of their predominant fuels. Included in sales for resale to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. Energy sales to these customers decreased 3.7 percent in 2001 and increased 10.9 percent in 2000, with the related revenues decreasing 2.4 percent and rising 10.8 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to those of the Company. Revenues from other sales outside the service area increased in 2001 when compared to 2000 as a result of a new long term contract made possible by the commercial operation of Plant Daniel Units 3 and 4. Energy sales to affiliated companies within the Southern Company electric system, as well as purchases, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales do not have a significant impact on earnings. Below is a breakdown of kilowatt-hour sales for 2001 and the percent change for the last two years: 2001 Percent Change ------------- --------------------------- KWH 2001 2000 (in millions) --------------------------- Residential 2,163 (5.4)% 1.7% Commercial 2,841 (1.5) 1.3 Industrial 4,276 (2.3) (0.7) Other 40 (0.3) 2.5 ------------- Total retail 9,320 (2.8) 0.5 Sales for Resale -- Non-affiliates 5,011 36.4 12.9 Affiliates 2,953 552.3 (16.2) ------------- Total 17,284 26.0 2.8 ================================================================== Residential sales decreased 5.4 percent due to unusually mild weather in the Company's service area. Commercial sales decreased 1.5 percent and industrial sales fell 2.3 percent due to an economic slowdown. Total retail kilowatt-hour sales increased slightly in 2000. This increase primarily resulted from the continued growth in the service area, increased tourism, and the positive impact of weather. Kilowatt-hour sales from outside the service area increased in 2001 when compared to 2000 as a result of a new contract made possible by the II-150 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report commercial operation of Plant Daniel Combined Cycle Units 3 and 4. Again, sales to affiliates will vary year to year depending on demand and cost of generating resources at each company. Expenses Total operating expenses were $663 million in 2001, reflecting an increase of $98 million or 17.4 percent over the prior year. The increase was due primarily to the commercial operation of Plant Daniel Combined Cycle Units 3 and 4. In 2000, total operating expenses increased by 10.1 percent over the prior year due primarily to higher fuel and purchased power expenses. Fuel costs are the single largest expense for the Company. Fuel expenses for 2001 and 2000 increased 45.4 percent and 10.7 percent, respectively. The increase for 2001 was due to increased generation especially from Plant Daniel Combined Cycle Units 3 and 4 and a higher average cost of fuel. The 2000 increase was due to increased generation and a higher average cost of fuel. In 2001, expenses related to purchased power from non-affiliates decreased 26.4 percent, while expenses related to purchased power from affiliates increased 5.7 percent which, in total, resulted in a 11.1 percent decrease when compared to 2000. This decrease in purchased power is primarily due to the commercial operation of Plant Daniel Combined Cycle Units 3 and 4 and the expiration of non-affiliated purchase power contracts in 2000. Sales and purchases among the Company and its affiliates will vary from period to period depending on demand and the availability and variable production cost of each generating unit in the Southern Company electric system. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows: 2001 2000 1999 ---------------------------- Total generation (millions of kilowatt hours) 15,770 11,688 11,599 Sources of generation (percent) -- Coal 59 83 81 Gas 41 17 19 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.89 1.80 1.65 ---------------------------------------------------------------- Other operation expenses increased 17.2 percent in 2001 primarily due to an increase in other production expenses due to the commercial operation of Plant Daniel Combined Cycle Units 3 and 4. In 2000, other operation expense decreased 8.2 percent primarily due to a decrease in administrative and general expenses. Maintenance expense in 2001 increased primarily due to the commercial operation of Plant Daniel Combined Cycle Units 3 and 4, while maintenance expense in 2000 increased primarily due to additional scheduled maintenance. Depreciation and amortization expense increased 7.6 percent in 2001 due to a growth in plant investment and the amortization of the Company's regulatory asset related to its Environmental Compliance Overview Plan (ECO Plan). In 2000, depreciation expense increased slightly due to growth in plant investment and new depreciation rates, which became effective January 2000. Taxes other than income taxes decreased 7.6 percent in 2001 due to reduced ad valorem taxes related to a change in the tax rate. These taxes increased 1.7 percent in 2000 due to higher municipal franchise taxes resulting from higher retail revenues. Interest on long-term debt decreased in 2001 as a result of lower interest rates on debt outstanding. Effects of Inflation The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical costs does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed. Future Earnings Potential General The results of continuing operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's II-151 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report future earnings depends on numerous factors ranging from weather to energy sales growth to a less regulated and more competitive environment. Expenses are subject to constant review and cost control programs. The Company is also maximizing the utility of invested capital and minimizing the need for additional capital by refinancing outstanding obligations, managing the size of its fuel stockpile, raising generating plant availability and efficiency, and aggressively controlling its construction budget. The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in southeastern Mississippi. Prices for electricity provided by the Company to retail customers are set by the Mississippi Public Service Commission (MPSC) under cost-based regulatory principles. The Federal Energy Regulatory Commission (FERC) regulates the Company's wholesale rate schedules, power sales contracts, and transmission facilities. Operating revenues will be affected by any changes in rates under the Performance Evaluation Plan (PEP) -- the Company's performance based ratemaking plan -- and the ECO Plan. PEP has proven to be a stabilizing force on electric rates, with only moderate changes in rates taking place. The ECO Plan provides for recovery of costs (including costs of capital) associated with environmental projects approved by the MPSC, most of which are required to comply with Clean Air Act Amendments of 1990 (Clean Air Act) and the regulations thereunder. The ECO Plan is operated independently of PEP. Compliance costs related to the Clean Air Act could affect earnings if such costs cannot be recovered. The Company filed its 2001 ECO Plan in January 2001 which was approved, as filed, by the Mississippi PSC on March 7, 2001, and resulted in a slight increase in customer prices. The Company filed its 2002 ECO Plan in January 2002, which, if approved as filed, will result in a slight increase in rates. See Note 3 to the financial statements under "Litigation and Regulatory Matters" for additional information. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters." In August 2001, the Company filed a request with the MPSC for a retail rate increase of approximately $46 million. In order to consider the Company's request, the MPSC suspended the semi-annual evaluations under PEP. In December 2001, after a full investigation and hearing on the Company's request, the MPSC approved an increase of approximately $39 million, which took effect in January 2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual evaluations under PEP, beginning in February 2003 for the year 2002. PEP will remain in effect until the MPSC modifies, suspends, or terminates the plan. The MPSC also set for hearing in 2002 a review of the return on equity models used in PEP in setting the Company's authorized return on equity. This proceeding will conclude in 2002, so that changes to the PEP return on equity models, if any, may be incorporated into the February 2003 PEP evaluation filing for the period ending December 31, 2002. The outcome of this matter and any future impact to the Company cannot now be determined. In February 2002, the Company reached an agreement with certain of its wholesale customers to increase its wholesale tariff rates effective June 2002. The agreement results in an annual increase of approximately $10.5 million and the adoption of an Energy Cost Management clause similar to the one approved by the Company's retail jurisdiction (see Note 1 to the financials). In addition, the Company and its customers agreed that neither party would seek a unilateral change to the new rates prior to December 31, 2003, except for changes due to the operation of the fuel adjustment and energy cost management clauses. The Company and its customers will file the agreement with the FERC for its approval. Though the FERC has accepted settlement agreements as filed in the past, the ultimate outcome of this matter before the FERC cannot now be determined. In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income of approximately $3.2 million in 2001. Future pension income is dependent on several factors including trust earnings and changes to the plan. For the Company, pension income is a component of the regulated rates and does not have a significant effect on net income. For more information, see Note 2 to the financial statements. The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings. II-152 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report Compliance costs related to current and future environmental laws, regulations, and litigation could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters." Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area. The Company anticipates somewhat slower growth in energy sales as the tourism industry stabilizes within its service area. In addition to tourism, the healthcare and retail trade sectors will provide most of the anticipated energy growth for the commercial class of customers, while shipbuilding, chemicals, and the U.S. government will provide much of the basis for anticipated growth in the industrial sector. Industry Restructuring The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives are in various stages to promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. As these initiatives materialize, the structure of the utility industry could radically change. In May 2000, the MPSC ordered that its docket reviewing restructuring of the electric industry in the State of Mississippi be suspended. The MPSC found that retail competition may not be in the public interest at this time, and ordered that no further formal hearings would be held on this subject. It found that the current regulatory structure produced reliable low cost power and "should not be changed without clear and convincing demonstration that change would be in the public interest." The MPSC will continue to monitor retail and wholesale restructuring activities throughout the United States and reserves its right to order further formal hearings on the matter should new evidence demonstrate that retail competition would be in the public interest and all customers could receive a reduction in the total cost of their electric service. If the MPSC decides to hold future restructuring hearings on this matter, enactment would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California. As a result of that crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. Continuing to be a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, unless the Company remains a low-cost producer and provides quality service, the Company's energy sales growth could be limited, and this could significantly erode earnings. In December 1999, the FERC issued its final ruling on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its operating companies, including the Company, have submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In January 2002, the sponsors of SeTrans held a public meeting to form a Stakeholder Advisory Committee, which will participate in the development of the RTO. Southern Company continues to work with the other sponsors to develop the SeTrans RTO. While the creation of SeTrans is not expected to have a material impact on the Company's financial statements, the outcome of this matter cannot now be determined. II-153 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report Accounting Policies Critical Policies The Company's significant accounting policies are described in Note 1 to the financial statements. The Company's most critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operation is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information. Additionally, the Company accounts for its lease agreement with Escatawpa Funding, Limited Partnership (Escatawpa) as an operating lease. Under this agreement, Escatawpa, a special purpose entity, is owner-lessor of the combined-cycle generating units at the Company's Plant Daniel. The Company does not consolidate this entity since parties unrelated to the Company have made substantive residual equity capital investments in excess of 3 percent. The FASB has recently issued a draft interpretation that addresses issues related to identifying and accounting for certain special purpose entities. One proposed change would increase the 3 percent outside equity requirement to 10 percent. This interpretation is in draft form; therefore, final conclusions may differ from the draft. However, a change to a ten percent equity requirement could result in the Company having to change its accounting for this lease agreement, including having to consolidate the leased asset and related debt. See Note 4 to the financial statements where the lease agreement and the Company's related obligations are discussed. New Accounting Standards Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Statement No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value, and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. See Note 1 to the financial statements under "Financial Instruments" for additional information. The impact on the Company's net income in 2001 was not material. An additional interpretation of Statement No. 133 will result in a change - effective April 1, 2002 - in accounting for certain contracts related to fuel supplies that contain quantity options. These contracts will be accounted for as derivatives and marked to market. However, due to the existence of the Company's cost-based fuel recovery clause, this change is not expected to have a material impact on net income. In June 2001, the FASB issued Statement No. 142, Goodwill and Other Intangible Assets, which establishes new accounting and reporting standards for acquired goodwill and other intangible assets and supersedes Accounting Principles Board Opinion No. 17. Statement No. 142 addresses how intangible assets that are acquired individually or with a group of other assets -- but not those acquired in a business combination -- should be accounted for upon acquisition and on an ongoing basis. Goodwill and intangible assets that have indefinite useful lives will not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives, which are no longer limited to 40 years. The Company adopted Statement No.142 in January 2002 with no material impact on the financial statements. Also in June 2001, the FASB issued Statement No. 143, Asset Retirement Obligations, which establishes new accounting and reporting standards for legal obligations associated with retiring assets, including decommissioning of nuclear plants. The liability for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The Company has not yet quantified the impact of adopting Statement No. 143 on its financial statements. FINANCIAL CONDITION Overview The principal change in the Company's financial condition during 2001 was the addition of approximately $61 million to utility plant. Funding for these II-154 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report additions and other capital requirements were derived primarily from operations. The Statements of Cash Flows provide additional details. Credit Rating Risk The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain fixed-price physical gas purchase contracts that could require collateral - but not accelerated payment - in the event of a credit rating change to below investment grade; however, at December 31, 2001, this exposure was immaterial. Exposure to Market Risks Due to cost-based rate regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statements as incurred. At December 31, 2001, exposure from these activities was not material to the Company's financial statements. Also, based on the Company's overall variable rate long-term debt exposure at December 31, 2001, a near-term 100 basis point change in interest rates would not materially affect the Company's financial statements. Fair value of changes in energy trading contracts and year-end valuations are as follows: Changes During the Year ---------------------- Fair Value ---------------------------------------------------------------- (in thousands) Contracts beginning of year $ 112 Contracts realized or settled (101) New contracts at inception - Changes in valuation techniques - Current period changes (3,841) ----------------------------------------------------------------- Contracts end of year $ (3,830) ================================================================= Source of Year-End Valuation Prices ----------------------------------- Maturity Total -------------------- Fair Value Year 1 1-3 Years ----------------------------------------------------------------- (in thousands) ----------------------------------------------------------------- Actively quoted $(3,830) $(3,517) $ (313) External sources - - - Models and other methods - - - ----------------------------------------------------------------- Contracts end of year $(3,830) $(3,517) $ (313) ================================================================= For additional information, see Note 1 to the financial statements under "Financial Instruments." In June 2001, the MPSC approved the Company's request to implement an Energy Cost Management Clause (ECM). ECM, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Amounts paid or received as a result of the use of these instruments are recognized as fuel related expense and are recovered or credited through the ECM factor calculated annually and applied to customer billings. The Company records the fair value of these financial instruments (cash flow hedges) in its financial statements in accordance with FASB Statement No. 133 with a related regulatory asset or liability recorded under the provisions of FASB Statement No. 71. As of December 31, 2001, the Company had financial instruments related to natural gas commodity contracts that had a contract value of approximately $31 million and $30 million expiring in 2002 and 2003, respectively. The market values as of December 31, 2001 for these contracts were approximately $27 million and $30 million, respectively. The amounts settled and recognized in the financial statements for 2001 were not material. Currently, the Company does not have any fixed price natural gas commitments, either physical or financial, beyond 2003. Sources of Capital To meet short-term cash needs and contingencies, the Company had at December 31, 2001 approximately $18.9 million of cash and cash equivalents and approximately $114.5 million of unused committed credit agreements. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company operating companies. II-155 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report At December 31, 2001, the Company had outstanding $16 million of commercial paper. It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived from sources similar to those used in the past. These sources were primarily the issuance of first mortgage bonds and preferred securities, in addition to pollution control revenue bonds issued for the Company's benefit by public authorities. The Company also utilized unsecured debt and lease arrangements in the past as well. The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, the Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's coverage ratios are high enough to permit, at present interest rate levels, any foreseeable security sales. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time. Financing Activity In May 2001, the Company received a $70 million capital contribution which was used to retire $35 million of 6.60 percent first mortgage bonds, $20 million of series C variable-rate senior notes, and $15 million in short term debt. The Company plans to continue, to the extent possible, a program to retire higher-cost debt and replace these securities with lower-cost capital. See the Statements of Cash Flows for further details. Composite financing rates decreased for the year 2001 when compared to 2000 and 1999. As of year-end, the composite rates were as follows: 2001 2000 1999 ------------------------------- Composite interest rate on long-term debt 4.60% 6.41% 6.19% Composite preferred stock dividend rate 6.33% 6.33% 6.33% Composite interest rate on preferred securities 7.75% 7.75% 7.75% -------------------------------------------------------------- Off-Balance Sheet Financing Arrangements In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa. These agreements called for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility at the Company's Plant Victor J. Daniel Facility (Facility). In May 2001, the Facility was completed and placed into commercial operation. Effective with commercial operation of the Facility, the initial 10-year lease term under its lease arrangement for the Facility with Escatawpa began. The completion cost was approximately $370 million. The lease provides for a residual value guarantee (approximately 71% of the completion cost) by the Company that is due upon termination of the lease in certain circumstances. The lease also includes purchase and renewal options. Upon termination of the lease, at the Company's option, the Company may either exercise its purchase option or the Facility can be sold to a third party. The Company expects that the fair market value of the leased Facility would substantially reduce or eliminate the Company's payment under the residual value guarantee. In 2001, the Company recognized approximately $18 million in lease expense. See Note 4 to the financial statements for additional information. Capital Structure At year-end 2001, the Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, increased from 48.1 percent in 2000 to 62.1 percent. The Company plans to replace the long-term debt due within one year with new issues. Capital Requirements for Construction The Company's projected construction expenditures for the next three years total $241 million ($84 million in 2002, $72 million in 2003, and $85 million in 2004). The major emphasis within the construction program will be on the upgrade of existing facilities. Revisions to projected construction expenditures may be necessary because of factors such as changes in business conditions, revised load projections, the availability and cost of capital, changes in environmental regulations, and alternatives such as leasing. II-156 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report Other Capital Requirements In addition to the funds required for the Company's construction program, approximately $115 million will be required by the end of 2003 for present sinking fund requirements and maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit. These capital requirements, lease obligations, and purchase commitments - discussed in notes 4 and 8 to the financial statements - are as follows: 2002 2003 2004 ---------------------------------------------------------- (in thousands) Bonds - First mortgage $ - $ - $ - Pollution control 20 25 25 Notes 80,000 35,000 - Lease obligations 27,000 27,000 27,000 Purchase commitments Fuel 225,000 188,000 7,000 Purchased power - - - ----------------------------------------------------------- At the beginning of 2002, the Company had not used any of its available credit arrangements. Credit arrangements are as follows: Expires ----------------------------- Total Unused 2002 2003 & Beyond ------------------------------------------------------------ (in millions) $114.5 $114.5 $109.5 5.0 ------------------------------------------------------------ Environmental Matters On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action in the U.S. District Court against Alabama Power Company, Georgia Power Company, and the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously, and the Company's plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Savannah Electric, and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add Gulf Power and the Company based on lack of jurisdiction over those companies. The court directed the EPA to re-file its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. The EPA re-filed those claims as directed by the court. Also, the EPA re-filed its claims against Alabama Power in U.S. District Court in Alabama. It has not re-filed against Gulf Power, the system service company, or the Company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case could have a significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and Savannah Electric have opposed that motion. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was II-157 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates. In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Southern Company. Reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995. Southern Company achieved Phase I compliance at its affected plants by primarily switching to low-sulfur coal and with some equipment upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $65 million for the Company. Phase II sulfur dioxide compliance was required in 2000. Southern Company used emission allowances and fuel switching to comply with Phase II requirements. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Phase II compliance did not have a material impact on the Company. The Company's ECO Plan is designed to allow recovery of costs of compliance with the Clean Air Act, as well as other environmental statutes and regulations. The MPSC reviews environmental projects and the Company's environmental policy through the ECO Plan. Under the ECO Plan, any increase in the annual revenue requirement is limited to 2 percent of retail revenues. The Company's management believes that the ECO Plan provides for recovery of the Clean Air Act costs. See Note 3 to the financial statements under "Environmental Compliance Overview Plan" for additional information. A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered. In July 1997, the EPA revised the national ambient air quality standards for ozone and fine particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals is considering other legal challenges to these standards. A court decision is expected in the spring of 2002. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May 31, 2004 for most states including Alabama. For Georgia, further rulemaking was required, and proposed compliance was delayed until May 1, 2005. The final rules affect 21 states that do not include Mississippi. The EPA is presently evaluating whether or not to bring an additional 15 states including Mississippi, under this regional nitrogen oxide rule. In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act, and the regulations are scheduled to be finalized by the end of 2004 with implementation to take place around 2007. In January 2001, the EPA proposed guidance for the determination of Best Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls is expected to take place in 2010. Litigation of the Regional Haze Regulations, including the BART provisions, is ongoing in the Federal District of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002. Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide and reductions in mercury and other HAPS emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and II-158 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2001 Annual Report standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. In October 1997, the EPA issued regulations setting forth requirements for Compliance Assurance Monitoring (CAM) in its state and federal operating permit programs. These regulations were amended by the EPA in March 2001 in response to a court order resolving challenges to the rules brought by environmental groups and industry. Generally, this rule affects the operation and maintenance of electrostatic precipitators and could involve significant additional ongoing expense. The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur costs to clean up properties currently or previously owned. Upon identifying potential sites, the Company conducts studies, when possible, to determine the extent of any required cleanup. Should remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect the Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields. Cautionary Statement Regarding Forward-Looking Information This Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning projected sales growth and scheduled completion of new generation. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "could," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "projects," "potential," or "continue" or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental 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, including the pending EPA civil action against the Company; the effects, extent and timing of the entry of additional competition in the markets of the Company; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; 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 effects of, and changes in, economic conditions in the areas in which the Company operates; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and acceptance of the Company's new product and service offerings; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission. 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STATEMENTS OF INCOME For the Years Ended December 31, 2001, 2000, and 1999 Mississippi Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------- 2001 2000 1999 -------------------------------------------------------------------------------------------------------------- (in thousands) Operating Revenues: Retail sales $489,153 $498,551 $469,434 Sales for resale -- Non-affiliates 204,623 145,931 131,004 Affiliates 85,652 27,915 19,446 Other revenues 16,637 15,205 13,120 -------------------------------------------------------------------------------------------------------------- Total operating revenues 796,065 687,602 633,004 -------------------------------------------------------------------------------------------------------------- Operating Expenses: Operation -- Fuel 277,946 191,127 172,686 Purchased power -- Non-affiliates 41,254 56,082 40,080 Affiliates 53,990 51,057 31,007 Other 134,845 115,055 125,291 Maintenance 56,153 52,750 47,085 Depreciation and amortization 54,077 50,275 49,206 Taxes other than income taxes 44,966 48,686 47,893 -------------------------------------------------------------------------------------------------------------- Total operating expenses 663,231 565,032 513,248 -------------------------------------------------------------------------------------------------------------- Operating Income 132,834 122,570 119,756 Other Income (Expense): Interest income 369 347 189 Other, net (532) (647) 1,675 -------------------------------------------------------------------------------------------------------------- Earnings Before Interest and Income Taxes 132,671 122,270 121,620 -------------------------------------------------------------------------------------------------------------- Interest Expense and Other: Interest expense, net 23,568 28,101 27,969 Distributions on preferred securities of subsidiary 2,712 2,712 2,712 -------------------------------------------------------------------------------------------------------------- Total interest charges and other, net 26,280 30,813 30,681 -------------------------------------------------------------------------------------------------------------- Earnings Before Income Taxes 106,391 91,457 90,939 Income taxes 40,533 34,356 34,117 -------------------------------------------------------------------------------------------------------------- Earnings Before Cumulative Effect of 65,858 57,101 56,822 Accounting Change Cumulative effect of accounting change-- less income taxes of $43 thousand 70 - - -------------------------------------------------------------------------------------------------------------- Net Income 65,928 57,101 56,822 Dividends on Preferred Stock 2,041 2,129 2,013 -------------------------------------------------------------------------------------------------------------- Net Income After Dividends on Preferred Stock $ 63,887 $ 54,972 $ 54,809 ============================================================================================================== The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001, 2000, and 1999 Mississippi Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 ----------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Activities: Net income $ 65,928 $ 57,101 $ 56,822 Adjustments to reconcile net income to net cash provided from operating activities -- Depreciation and amortization 58,105 54,638 53,427 Deferred income taxes and investment tax credits, net (9,718) 752 (4,143) Other, net 2,441 (1,747) 5,531 Changes in certain current assets and liabilities -- Receivables, net (7,796) (3,231) (39,304) Fossil fuel stock (20,269) 14,577 (9,379) Materials and supplies (1,529) (1,056) (1,903) Accounts payable 53,462 1,309 1,391 Other 11,251 2,952 14,206 ----------------------------------------------------------------------------------------------------------------------- Net cash provided from operating activities 151,875 125,295 76,648 ----------------------------------------------------------------------------------------------------------------------- Investing Activities: Gross property additions (61,193) (81,211) (75,888) Other (2,988) (9,153) 1,009 ----------------------------------------------------------------------------------------------------------------------- Net cash used for investing activities (64,181) (90,364) (74,879) ----------------------------------------------------------------------------------------------------------------------- Financing Activities: Increase (decrease) in notes payable, net (40,027) (1,500) 44,500 Proceeds -- Other long-term debt - 100,000 59,400 Capital contributions from parent company 73,095 12,659 2,028 Retirements -- First mortgage bonds (36,000) - - Other long-term debt (21,021) (81,405) (50,456) Preferred stock - - - Payment of preferred stock dividends (2,041) (2,129) (2,013) Payment of common stock dividends (50,200) (54,700) (56,100) Other (81) (498) (282) ----------------------------------------------------------------------------------------------------------------------- Net cash used for financing activities (76,275) (27,573) (2,923) ----------------------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents 11,419 7,358 (1,154) Cash and Cash Equivalents at Beginning of Period 7,531 173 1,327 ----------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 18,950 $ 7,531 $173 ======================================================================================================================= Supplemental Cash Flow Information: Cash paid during the period for -- Interest (net of amount capitalized) $28,126 $30,570 $25,486 Income taxes (net of refunds) 45,761 33,276 39,729 ----------------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of these statements.
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BALANCE SHEETS At December 31, 2001 and 2000 Mississippi Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------- Assets 2001 2000 ------------------------------------------------------------------------------------------------------------------------- (in thousands) Current Assets: Cash and cash equivalents $ 18,950 $ 7,531 Receivables -- Customer accounts receivable 63,286 72,064 Other accounts and notes receivable 26,068 21,843 Affiliated companies 22,569 10,071 Accumulated provision for uncollectible accounts (856) (571) Fossil fuel stock, at average cost 31,489 11,220 Materials and supplies, at average cost 23,223 21,694 Other 16,002 8,320 ------------------------------------------------------------------------------------------------------------------------- Total current assets 200,731 152,172 ------------------------------------------------------------------------------------------------------------------------- Property, Plant, and Equipment: In service 1,741,499 1,665,879 Less accumulated provision for depreciation 698,681 652,891 ------------------------------------------------------------------------------------------------------------------------- 1,042,818 1,012,988 Construction work in progress 38,253 60,951 ------------------------------------------------------------------------------------------------------------------------- Total property, plant, and equipment 1,081,071 1,073,939 ------------------------------------------------------------------------------------------------------------------------- Other Property and Investments 1,900 2,268 ------------------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets: Deferred charges related to income taxes 13,394 13,860 Prepaid pension costs 4,501 434 Debt expense, being amortized 4,396 4,628 Premium on reacquired debt, being amortized 6,719 7,168 Other 20,821 14,312 ------------------------------------------------------------------------------------------------------------------------- Total deferred charges and other assets 49,831 40,402 ------------------------------------------------------------------------------------------------------------------------- Total Assets $1,333,533 $1,268,781 ========================================================================================================================= The accompanying notes are an integral part of these balance sheets.
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BALANCE SHEETS At December 31, 2001 and 2000 Mississippi Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------- Liabilities and Stockholder's Equity 2001 2000 ----------------------------------------------------------------------------------------------------------------------- (in thousands) Current Liabilities: Securities due within one year $ 80,020 $ 20 Notes payable 15,973 56,000 Accounts payable -- Affiliated 6,175 10,715 Other 105,834 48,146 Customer deposits 6,540 5,274 Taxes accrued -- Income taxes 14,981 8,769 Other 35,282 36,799 Interest accrued 5,079 4,482 Vacation pay accrued 5,810 5,701 Other 11,483 6,473 ----------------------------------------------------------------------------------------------------------------------- Total current liabilities 287,177 182,379 ----------------------------------------------------------------------------------------------------------------------- Long-term debt (See accompanying statements) 233,753 370,511 ----------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 138,913 139,909 Deferred credits related to income taxes 23,626 25,603 Accumulated deferred investment tax credits 22,268 23,481 Employee benefits provisions 31,041 28,911 Workforce reduction plan 8,263 9,734 Other 30,003 16,546 ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 254,114 244,184 ----------------------------------------------------------------------------------------------------------------------- Company obligated mandatorily redeemable preferred securities of subsidiary trust holding company junior subordinated notes (See accompanying statements) 35,000 35,000 ----------------------------------------------------------------------------------------------------------------------- Preferred stock (See accompanying statements) 31,809 31,809 ----------------------------------------------------------------------------------------------------------------------- Common stockholder's equity (See accompanying statements) 491,680 404,898 ----------------------------------------------------------------------------------------------------------------------- Total Liabilities and Stockholder's Equity $1,333,533 $1,268,781 ======================================================================================================================= The accompanying notes are an integral part of these balance sheets.
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STATEMENTS OF CAPITALIZATION At December 31, 2001 and 2000 Mississippi Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Long-Term Debt: First mortgage bonds -- Maturity Interest Rates -------- ------------- June 1, 2023 7.45% $ 34,000 $ 35,000 March 1, 2004 6.60% - 35,000 December 1, 2025 6.875% 30,000 30,000 ----------------------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 64,000 100,000 ----------------------------------------------------------------------------------------------------------------------------- Long-term notes payable -- 6.05% due May 1, 2003 35,000 35,000 6.75% due June 30, 2038 52,178 53,179 Adjustable rates (2.0056% at 1/1/02) due 2000-2002 80,000 100,000 ----------------------------------------------------------------------------------------------------------------------------- Total long-term notes payable 167,178 188,179 ----------------------------------------------------------------------------------------------------------------------------- Other long-term debt -- Pollution control revenue bonds -- Collateralized: 5.65% to 5.80% due 2007-2023 26,745 26,765 Non-collateralized: Variable rates (1.90% to 2.00% at 1/1/02) due 2020-2028 56,820 56,820 ----------------------------------------------------------------------------------------------------------------------------- Total other long-term debt 83,565 83,585 ----------------------------------------------------------------------------------------------------------------------------- Unamortized debt premium (discount), net (970) (1,233) ----------------------------------------------------------------------------------------------------------------------------- Total long-term debt (annual interest requirement -- $14.5 million) 313,773 370,531 Less amount due within one year 80,020 20 ----------------------------------------------------------------------------------------------------------------------------- Long-term debt excluding amount due within one year $233,753 $370,511 29.5% 43.9% -----------------------------------------------------------------------------------------------------------------------------
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STATEMENTS OF CAPITALIZATION (continued) At December 31, 2001 and 2000 Mississippi Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Company Obligated Mandatorily Redeemable Preferred Securities:(Note 8) $25 liquidation value -- 7.75% $ 35,000 $ 35,000 ----------------------------------------------------------------------------------------------------------------------------- Total (annual distribution requirement -- $2.7 million) 35,000 35,000 4.4 4.2 ----------------------------------------------------------------------------------------------------------------------------- Cumulative Preferred Stock: $100 par value 4.40% to 7.00% 31,809 31,809 ----------------------------------------------------------------------------------------------------------------------------- Total (annual dividend requirement -- $2.0 million) 31,809 31,809 4.0 3.8 ----------------------------------------------------------------------------------------------------------------------------- Common Stockholder's Equity: Common stock, without par value -- Authorized - 1,130,000 shares Outstanding - 1,121,000 shares in 2001 and 2000 37,691 37,691 Paid-in capital 267,256 194,161 Premium on preferred stock 326 326 Retained earnings 186,407 172,720 ----------------------------------------------------------------------------------------------------------------------------- Total common stockholder's equity 491,680 404,898 62.1 48.1 ----------------------------------------------------------------------------------------------------------------------------- Total Capitalization $792,242 $842,218 100.0% 100.0% ============================================================================================================================= The accompanying notes are an integral part of these statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2001, 2000, and 1999 Mississippi Power Company 2001 Annual Report --------------------------------------------------------------------------------------------------------------------------- Premium on Common Paid-In Preferred Retained Stock Capital Stock Earnings Total --------------------------------------------------------------------------------------------------------------------------- (in thousands) Balance at January 1, 1999 $37,691 $179,474 $326 $173,740 $391,231 Net income after dividends on preferred stock - - - 54,809 54,809 Capital contributions from parent company - 2,028 - - 2,028 Cash dividends on common stock - - - (56,100) (56,100) --------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 37,691 181,502 326 172,449 391,968 Net income after dividends on preferred stock - - - 54,972 54,972 Capital contributions from parent company - 12,659 - - 12,659 Cash dividends on common stock - - - (54,700) (54,700) Other - - - (1) (1) --------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 37,691 194,161 326 172,720 404,898 Net income after dividends on preferred stock - - - 63,887 63,887 Capital contributions from parent company - 73,095 - - 73,095 Cash dividends on common stock - - - (50,200) (50,200) --------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 $37,691 $267,256 $326 $186,407 $491,680 =========================================================================================================================== The accompanying notes are an integral part of these statements.
II-166 NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 2001 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Mississippi Power Company is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern LINC), Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern Power), and other direct and indirect subsidiaries. The operating companies -- Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four southeastern states. Contracts among the operating companies -- related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Mississippi Public Service Commission (MPSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by the respective 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. Prior years' data presented in the financial statements have been reclassified to conform with the current year presentation. Affiliate Transactions The Company has an agreement with the system service company under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension 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 $44.1 million, $46.2 million, and $45.5 million during 2001, 2000, and 1999, respectively. Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following: 2001 2000 ------------------------- (in thousands) Deferred income tax charges $ 13,394 $ 13,860 Vacation pay 5,810 5,701 Premium on reacquired debt 6,719 7,168 Fuel commitments 4,328 - Property damage reserve (4,044) (3,519) Deferred income tax credits (23,626) (25,603) Other, net (1,066) (505) ---------------------------------------------------------------- Total $ 1,515 $ (2,898) ================================================================ II-167 NOTES (continued) Mississippi Power Company 2001 Annual Report In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value. Revenues and Fuel Costs The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Mississippi and to wholesale customers in the Southeast. Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes, certain qualifying environmental costs, and energy cost management activities. Revenues are adjusted for differences between actual allowable amounts and the amounts included in rates. The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues. Depreciation Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.5 percent in 2001, 3.5 percent in 2000, and 3.3 percent in 1999. 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. Depreciation expense includes an amount for the expected cost of removal of facilities. Income Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction, if applicable. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense except for the maintenance of coal cars and a portion of the railway track maintenance, which are charged to fuel stock. The cost of replacements of property -- exclusive of minor items of property -- is capitalized. Cash and Cash Equivalents For purposes of the Statements of Cash Flows, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Financial Instruments Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The 2001 impact on net income was immaterial. The Company uses derivative financial instruments to hedge exposure to fluctuations in interest rates and certain commodity prices. Gains and losses on qualifying hedges are deferred and recognized either as income or as an adjustment to the carrying amount of the hedged item when the transaction occurs. 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 and its affiliates, through the system service company acting as their agent, enters into commodity related forward and option contracts to limit II-168 NOTES (continued) Mississippi Power Company 2001 Annual Report exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of these bulk energy purchases and sales contracts meet the definition of a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. In many cases, these fuel and electricity contracts qualify for normal purchase and sale exceptions under Statement No. 133 and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses, and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income. In June 2001, the MPSC approved the Company's request to implement an Energy Cost Management Clause (ECM). ECM, among other things, allows the Company to utilize financial instruments that are used to hedge its fuel commitments. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company records the fair value of these financial instruments (cash flow hedges) in its financial statements in accordance with FASB Statement No. 133 with a related regulatory asset or liability recorded under the provisions of FASB Statement No. 71. As of December 31, 2001, the Company had financial instruments related to natural gas commodity contracts that had a contract value of approximately $31 million and $30 million expiring in 2002 and 2003, respectively. The market values as of December 31, 2001 for these contracts were approximately $27 million and $30 million, respectively. The amounts settled and recognized in the financial statements for 2001 were not material. Currently, the Company does not have any fixed price natural gas commitments, either physical or financial, beyond 2003. The Company's other financial instruments for which the carrying amount did not equal fair value at December 31 were as follows: Carrying Fair Amount Value ------------------------ (in millions) Long-term debt: At December 31, 2001 $314 $309 At December 31, 2000 $371 $362 Capital trust preferred securities: At December 31, 2001 $ 35 $ 35 At December 31, 2000 $ 35 $ 34 ----------------------------------------------------------- The fair values for long-term debt and preferred securities were based on either closing market price or closing price of comparable instruments. Materials and Supplies Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when used or installed. Provision for Property Damage The Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by regulatory authorities, the Company accrues for the cost of such damage by charging expense and crediting an accumulated provision. The cost of repairing damage resulting from such events that individually exceed $50 thousand is charged to the accumulated provision. In 1999, an order from the MPSC increased the maximum Property Damage Reserve from $18 million to $23 million and allows an annual accrual of up to $4.6 million. In 2001, the Company provided for such costs by charges to income of $2.5 million. In 2000 and 1999, the Company provided for such costs by charges to income of $3.5 million and $4.4 million, respectively. As of December 31, 2001, the accumulated provision amounted to $4.0 million. 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan that covers substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all these employees may become eligible for such benefits when they retire. The Company funds trusts to II-169 NOTES (continued) Mississippi Power Company 2001 Annual Report the extent deductible under federal income tax regulations or the extent required by regulatory authorities. In late 2000, the Company adopted several pension and postretirement benefits plan changes that had the effect of increasing benefits to both current and future retirees. The measurement date for plan assets and obligations is September 30 for each year. Pension Plan Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations -------------------------- 2001 2000 --------------------------------------------------------------------- (in thousands) Balance at beginning of year $154,411 $148,657 Service cost 4,797 4,357 Interest cost 11,817 10,912 Benefits paid (8,456) (8,169) Actuarial gain and employee transfers 1,268 (1,646) Amendments 8,406 300 Other (76) - --------------------------------------------------------------------- Balance at end of year $172,167 $154,411 ===================================================================== Plan Assets -------------------------- 2001 2000 --------------------------------------------------------------------- (in thousands) Balance at beginning of year $256,648 $221,487 Actual return on plan assets (37,214) 39,737 Benefits paid (7,850) (7,593) Employee transfers (38) 3,017 --------------------------------------------------------------------- Balance at end of year $211,546 $256,648 ===================================================================== The accrued pension costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------------- (in thousands) Funded status $ 39,379 $ 102,238 Unrecognized transition obligation (2,716) (3,253) Unrecognized prior service cost 13,656 6,298 Unrecognized net gain (45,818) (104,849) --------------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 4,501 $ 434 ===================================================================== Components of the pension plans' net periodic cost were as follows: 2001 2000 1999 --------------------------------------------------------------- (in thousands) Service Cost $ 4,797 $ 4,357 $ 4,501 Interest cost 11,818 10,912 10,025 Expected return on plan assets (17,328) (15,910) (14,681) Recognized net gain (3,012) (2,577) (1,670) Net amortization 511 76 76 --------------------------------------------------------------- Net pension income $ (3,214) $ (3,142) $ (1,749) =============================================================== Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations --------------------------- 2001 2000 ---------------------------------------------------------------- (in thousands) Balance at beginning of year $44,952 $45,390 Service cost 922 830 Interest cost 3,411 3,309 Benefits paid (2,918) (2,628) Actuarial gain and employee transfers 3,256 (1,949) Amendments 1,900 - ---------------------------------------------------------------- Balance at end of year $51,523 $44,952 ================================================================ Plan Assets --------------------------- 2001 2000 ---------------------------------------------------------------- (in thousands) Balance at beginning of year $17,843 $14,998 Actual return on plan assets (1,888) 2,511 Employer contributions 3,232 2,961 Benefits paid (2,918) (2,627) ---------------------------------------------------------------- Balance at end of year $16,269 $17,843 ================================================================ II-170 NOTES (continued) Mississippi Power Company 2001 Annual Report The accrued postretirement costs recognized in the Balance Sheets were as follows: 2001 2000 ------------------------------------------------------------------ (in thousands) Funded status $(35,254) $(27,109) Unrecognized transition obligation 3,928 4,275 Unrecognized prior service cost 1,821 - Unrecognized net gain (40) (6,632) Fourth quarter contributions 1,268 1,065 ------------------------------------------------------------------ Accrued liability recognized in the Balance Sheets $(28,277) $(28,401) ================================================================== Components of the postretirement plans' net periodic cost were as follows: 2001 2000 1999 ------------------------------------------------------------------ (in thousands) Service cost $ 922 $ 830 $ 981 Interest cost 3,411 3,309 3,105 Expected return on plan assets (1,409) (1,235) $(1,100) Transition obligation 346 346 346 Prior service cost 80 - - Recognized net loss (38) - - ------------------------------------------------------------------ Net postretirement cost $ 3,312 $ 3,250 $ 3,332 ================================================================== The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits plan were: 2001 2000 --------------------------------------------------------------- Discount 7.50% 7.50% Annual salary increase 5.00 5.00 Long-term return on plan assets 8.50 8.50 --------------------------------------------------------------- An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 9.25 percent for 2001, decreasing gradually to 5.25 percent through the year 2010 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2001 as follows: 1 Percent 1 Percent Increase Decrease ----------------------------------------------------------------- (in thousands) Benefit obligation $4,037 $3,551 Service and interest costs 314 273 ----------------------------------------------------------------- Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2001, 2000, and 1999 were $2.5 million, $2.3 million, and $2.2 million, respectively. 3. LITIGATION AND REGULATORY MATTERS General The Company is subject to certain claims and legal actions arising in the ordinary course of business. In the opinion of management, after consultation with legal counsel, the ultimate disposition of these matters is not expected to have a material adverse effect on the Company's financial condition. Environmental Litigation On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court in Georgia against Alabama Power, Georgia Power and the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously, and the Company's plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation and to add Gulf Power, Savannah II-171 NOTES (continued) Mississippi Power Company 2001 Annual Report Electric and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add Gulf Power and the Company based on lack of jurisdiction over those companies. The court directed the EPA to re-file its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. The EPA re-filed those claims as directed by the court. Also, the EPA re-filed its claims against Alabama Power in U.S. District Court in Alabama. It has not re-filed against Gulf Power, the system service company, or the Company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case could have a significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and Savannah Electric have opposed that motion. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates. Retail Rate Adjustment Plans The Company's retail base rates are set under a Performance Evaluation Plan (PEP) approved by the MPSC in 1994. PEP was designed with the objective that the plan would reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low. PEP includes a mechanism for rate adjustments based on the Company's ability to maintain low rates for customers and on the Company's performance as measured by three indicators that emphasize price and service to the customer. PEP provides for semiannual evaluations of the Company's performance-based return on investment. Any change in rates is limited to 2 percent of retail revenues per evaluation period. In August 2001, the Company filed a request with the MPSC for a retail rate increase of approximately $46 million. In order to consider the Company's request, the MPSC suspended the semi-annual evaluations under PEP. In December 2001, after a full investigation and hearing on the Company's request, the MPSC approved an increase of approximately $39 million, which took effect in January 2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual evaluations under PEP, beginning in February 2003 for the year 2002. PEP will remain in effect until the MPSC modifies, suspends, or terminates the plan. The MPSC also set for hearing in 2002 a review of the return on equity models used in PEP in setting the Company's authorized return on equity. This proceeding will conclude in 2002, so that changes to the PEP return on equity models, if any, may be incorporated into the February 2003 PEP evaluation filing for the period ending December 31, 2002. The outcome of this matter and any future impact to the Company cannot now be determined. Environmental Compliance Overview Plan The MPSC approved the Company's Environmental Compliance Overview Plan (ECO Plan) in 1992. The ECO Plan establishes procedures to facilitate the MPSC's overview of the Company's environmental strategy and provides for recovery of costs (including costs of capital) associated with environmental projects approved by the MPSC. Under the ECO Plan, any increase in the annual revenue II-172 NOTES (continued) Mississippi Power Company 2001 Annual Report requirement is limited to 2 percent of retail revenues. However, the ECO Plan also provides for carryover of any amount over the 2 percent limit into the next year's revenue requirement. The Company conducts studies, when possible, to determine the extent of any required environmental remediation. Should such remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. The Company recovers such costs under the ECO Plan as they are incurred, as provided for in the Company's 1995 ECO Plan Order. The Company filed its 2002 ECO Plan in January, which, if approved as filed, will result in a slight increase in customer prices. Approval for New Capacity In January 1998, the Company was granted a Certificate of Public Convenience and Necessity by the MPSC to build approximately 1,064 megawatts of combined cycle generation at the Company's Plant Daniel site, to be placed in service by June 2001. In December 1998, the Company requested approval to transfer the ownership rights under the certificate to Escatawpa Funding, Limited Partnership (Escatawpa), which will lease the facility to the Company (see Note 4, Commitments). In September 2000, the Company and the Mississippi Public Utilities Staff entered, and the MPSC in October 2000 approved, a new stipulation that modifies a January 1999 stipulation and order covering cost allocation. The 1999 stipulation and MPSC order would have excluded the new capacity from retail rate base and would have assigned the Company's existing generating facilities entirely to the retail jurisdiction. The new stipulation and MPSC order allocates a pro-rata share of the new capacity along with the Company's existing generating capacity to the retail jurisdiction. The Company's 2001 retail rate case reflected this methodology and the MPSC's December 2001 order on the retail rate case filing approved the Company's cost allocations. 4. COMMITMENTS Construction Program The Company is engaged in continuous construction programs, the costs of which are currently estimated to total $84 million in 2002, $72 million in 2003, and $85 million in 2004. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; revised load growth estimates; changes in environmental regulations; increasing costs of labor, equipment and materials; and cost of capital. Significant construction will continue related to transmission and distribution facilities, and the upgrading of generating plants. Lease Agreements In 1989, the Company entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars. In 1994, a second lease agreement for the use of 250 additional aluminum railcars was also entered into for twenty-two years. The Company has the option to purchase the 745 railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. Both of these leases were for the transport of coal to Plant Daniel. Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible for one half of the lease cost. The Company's share (50%) of the leases, charged to fuel stock, was $1.9 million in 2001, $2.1 million in 2000, and $2.8 million in 1999. The Company's annual lease payments for 2002 through 2006 will average approximately $2.0 million and after 2006, lease payments total in aggregate approximately $12 million. In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa Funding, Limited Partnership (Escatawpa). These agreements called for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility at the Company's Plant Victor J. Daniel Facility (Facility). In May 2001, the Facility was completed and placed into commercial operation. Effective with commercial operation of the Facility at Plant Daniel, the initial 10-year lease term under its lease arrangement for the Facility with Escatawpa began. The completion cost was approximately $370 million. The lease provides for a residual value guarantee (approximately 71% of the completion cost) by the Company that is due upon termination of the lease in certain circumstances. The lease also includes a purchase and renewal option. Upon termination of the lease, at the Company's option, the Company may either exercise its purchase option or the Facility can be sold to a third party. The Company expects that the fair market value of the leased Facility would II-173 NOTES (continued) Mississippi Power Company 2001 Annual Report substantially reduce or eliminate the Company's payment under the residual value guarantee. In 2001, the Company recognized approximately $18 million in lease expense. The Company estimates that its annual amount of future minimum operating lease payments, exclusive of any payment related to the residual value guarantee, as of December 31, 2001, were as follows: Year Lease Payments ---- -------------- (in millions) 2002 $26.4 2003 25.5 2004 25.2 2005 25.0 2006 24.7 2007 and thereafter 143.0 ---------------------------------------------------------- Total commitments $269.8 ========================================================== Fuel 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 fuel. In most cases, these contracts contain provisions for price escalations, minimum production levels, and other financial commitments. In addition, the Company utilizes financial instruments to eliminated price volatility. Total estimated fixed-price obligations at December 31, 2001, were as follows: Year Fuel ---- ---- (in millions) 2002 $225 2003 188 2004 7 2005 7 2006 7 2007 and thereafter 86 ---------------------------------------------------------- Total commitments $520 ========================================================== In addition, the system service company acts as agent for the five operating companies and Southern Power with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes allocated based on usage projections, as of December 31, 2001 are as follows: Year Natural Gas ---- ----------- (MMBtu) 2002 40,345,416 2003 39,723,953 2004 22,521,216 2005 11,161,628 2006 8,044,570 2007 and thereafter 2,981,474 ------------------------------------------------------------ Total commitments 124,778,257 ============================================================ Additional commitments for fuel will be required in the future to supply the Company's fuel needs. 5. JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own as tenants in common Units 1 and 2 at Plant Greene County located in Alabama. Additionally, the Company and Gulf Power own as tenants in common Units 1 and 2 at Plant Daniel located in Mississippi. At December 31, 2001, the Company's percentage ownership and investment in these jointly owned facilities were as follows: Company's Generating Total Percent Gross Accumulated Plant Capacity Ownership Investment Depreciation ----- -------- --------- ---------- ------------ (Megawatts) (in thousands) Greene County Units 1 and 2 500 40% $ 65,486 $ 35,116 Daniel Units 1 and 2 1,000 50% $236,979 $116,766 -------------------------------------------------------------- The Company's share of plant operating expenses is included in the corresponding operating expenses in the Statements of Income. 6. LONG-TERM CAPACITY SALES AND LEASE AGREEMENTS The Company and the other operating companies of Southern Company have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The Company's capacity revenues under these agreements were not material during the periods reported. II-174 NOTES (continued) Mississippi Power Company 2001 Annual Report In 1984, the Company and Entergy Corp. (formerly Gulf States Utilities) entered into a 40-year transmission facilities agreement whereby Entergy began paying a use fee to the Company covering all expenses relative to ownership and operation and maintenance of a 500 kV line, including amortization of its original $57 million cost. For the three years ended 2001, use fees collected under this agreement, net of related expenses, amounted to approximately $2.7 million each year and are included within Other Income in the Statements of Income. During 2000, the Company entered into a 10-year capacity lease that began in mid 2001. The minimum capacity lease revenue that the Company will receive will average approximately $21 million per year over the 10-year period. Capacity revenues for 2001 were approximately $12.3 million and were classified as sales for resale in the financial statements. 7. INCOME TAXES At December 31, 2001, the tax-related regulatory assets and liabilities were $13 million and $24 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Details of the federal and state income tax provisions are shown below: 2001 2000 1999 ---------------------------------- (in thousands) Total provision for income taxes Federal -- Current $43,596 $28,934 $33,379 Deferred (8,661) 622 (3,973) ----------------------------------------------------------------- 34,935 29,556 29,406 ----------------------------------------------------------------- State -- Current 6,698 4,670 4,881 Deferred (1,057) 130 (170) ----------------------------------------------------------------- 5,641 4,800 4,711 ----------------------------------------------------------------- Total $40,576 $34,356 $34,117 ================================================================= 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: 2001 2000 ------------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $147,147 $151,278 Basis differences 8,271 8,559 Other 34,544 24,136 --------------------------------------------------------------- Total 189,962 183,973 --------------------------------------------------------------- Deferred tax assets: Other property basis differences 15,983 17,147 Pension and other benefits 9,474 9,528 Property insurance 1,547 3,558 Unbilled fuel 5,596 5,727 Other 27,269 9,669 --------------------------------------------------------------- Total 59,869 45,629 --------------------------------------------------------------- Total deferred tax liabilities, net 130,093 138,344 Portion included in current assets, net 8,820 1,565 --------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $138,913 $139,909 =============================================================== Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $1.2 million in 2001, 2000, and 1999. At December 31, 2001, all investment tax credits available to reduce federal income taxes payable had been utilized. A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2001 2000 1999 -------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.4 3.4 Non-deductible book depreciation 0.5 0.6 0.7 Other (0.8) (1.5) (1.6) ---------------------------------------------------------------- Effective income tax rate 38.1% 37.5% 37.5% ================================================================ Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability. II-175 NOTES (continued) Mississippi Power Company 2001 Annual Report 8. CAPITALIZATION Preferred Securities In February 1997, Mississippi Power Capital Trust I (Trust I), of which the Company owns all the common securities, issued $35 million of 7.75 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust I are $36 million aggregate principal amount of the Company's 7.75 percent junior subordinated notes due February 15, 2037. The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trust's payment obligations with respect to the preferred securities. Trust I is a subsidiary of the Company, and accordingly is consolidated in the Company's financial statements. Long-Term Debt Due Within One Year A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year is as follows: 2001 2000 --------------------- (in thousands) Bond improvement fund requirement $ 650 $1,000 Less: Portion to be satisfied by certifying property additions 650 1,000 -------------------------------------------------------------- Cash sinking fund requirement - - Current portion of other long-term debt 80,000 - Pollution control bond cash sinking fund requirements 20 20 -------------------------------------------------------------- Total $80,020 $ 20 ============================================================== The first mortgage bond improvement fund requirement is one percent of each outstanding series authenticated under the indenture of the Company prior to January 1 of each year, other than first mortgage bonds issued as collateral security for certain pollution control obligations. The requirement must be satisfied by June 1 of each year by depositing cash or reacquiring bonds, or by pledging additional property equal to 166-2/3 percent of such requirement. Bank Credit Arrangements At December 31, 2001, the Company had total committed credit agreements with banks for approximately $114.5 million. At year-end 2001, the unused portion of these committed credit agreements was approximately $114.5 million. These credit agreements expire at various dates in 2002 and 2003. Some of these agreements allow short-term borrowings to be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at the Company's option. In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. The amount of commercial paper outstanding at December 31, 2001 was $16 million. Assets Subject to Lien The Company's mortgage indenture dated as of September 1, 1941, as amended and supplemented, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises. Dividend Restrictions The Company's first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 2001, approximately $118 million of retained earnings was restricted against the payment of cash dividends on common stock under the most restrictive terms of the mortgage indenture or corporate charter. II-176 NOTES (continued) Mississippi Power Company 2001 Annual Report 9. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data for 2001 and 2000 are as follows: Net Income After Dividends Operating Operating On Preferred Quarter Ended Revenues Income Stock ------------------------------------------------------------------- (in thousands) March 2001 $171,312 $23,615 $ 9,757 June 2001 203,949 32,640 16,571 September 2001 235,916 53,263 30,379 December 2001 184,888 23,315 7,180 March 2000 $134,705 $18,593 $ 6,722 June 2000 176,028 28,130 12,232 September 2000 220,119 53,943 28,762 December 2000 156,750 21,904 7,256 ------------------------------------------------------------------- The Company's business is influenced by seasonal weather conditions and the timing of rate changes. II-177
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 Mississippi Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 -------------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands)* $796,065 $687,602 $633,004 $595,131 $543,588 Net Income after Dividends on Preferred Stock (in thousands) $63,887 $54,972 $54,809 $55,105 $54,010 Cash Dividends on Common Stock (in thousands) $50,200 $54,700 $56,100 $51,700 $49,400 Return on Average Common Equity (percent) 14.25 13.80 14.00 14.15 14.00 Total Assets (in thousands) $1,333,533 $1,268,781 $1,251,136 $1,189,605 $1,166,829 Gross Property Additions (in thousands) $61,193 $81,211 $75,888 $68,231 $55,375 -------------------------------------------------------------------------------------------------------------------------------- Capitalization (in thousands): Common stock equity $491,680 $404,898 $391,968 $391,231 $387,824 Preferred stock 31,809 31,809 31,809 31,809 31,896 Company obligated mandatorily redeemable preferred securities 35,000 35,000 35,000 35,000 35,000 Long-term debt 233,753 370,511 321,802 292,744 291,665 -------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) $792,242 $842,218 $780,579 $750,784 $746,385 ================================================================================================================================ Capitalization Ratios (percent): Common stock equity 62.1 48.1 50.2 52.1 52.0 Preferred stock 4.0 3.8 4.1 4.2 4.3 Company obligated mandatorily redeemable preferred securities 4.4 4.2 4.5 4.7 4.7 Long-term debt 29.5 43.9 41.2 39.0 39.0 -------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 ================================================================================================================================ Security Ratings: First Mortgage Bonds - Moody's Aa3 Aa3 Aa3 Aa3 Aa3 Standard and Poor's A+ A+ AA- AA- AA- Fitch AA- AA- AA- AA- AA- Preferred Stock - Moody's A3 a1 a1 a1 a1 Standard and Poor's BBB+ BBB+ A- A A Fitch A A A A+ A+ Unsecured Long-Term Debt - Moody's A1 - - - - Standard and Poor's A - - - - Fitch A+ - - - - ================================================================================================================================ Customers (year-end): Residential 158,852 158,253 157,592 156,530 156,650 Commercial 32,538 32,372 31,837 31,319 31,667 Industrial 498 517 546 587 642 Other 173 206 202 200 200 -------------------------------------------------------------------------------------------------------------------------------- Total 192,061 191,348 190,177 188,636 189,159 ================================================================================================================================ Employees (year-end): 1,316 1,319 1,328 1,230 1,245 -------------------------------------------------------------------------------------------------------------------------------- * 1999 data includes the true-up of the unbilled revenue estimates.
II-178
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued) Mississippi Power Company 2001 Annual Report ------------------------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------------------ Operating Revenues (in thousands)*: Residential $ 164,716 $170,729 $159,945 $157,642 $138,608 Commercial 163,253 163,552 153,936 145,677 134,208 Industrial 156,525 159,705 151,244 135,039 140,233 Other 4,659 4,565 4,309 4,209 4,193 ------------------------------------------------------------------------------------------------------------------------------------ Total retail 489,153 498,551 469,434 442,567 417,242 Sales for resale - non-affiliates 204,623 145,931 131,004 121,225 105,141 Sales for resale - affiliates 85,652 27,915 19,446 18,285 10,143 ------------------------------------------------------------------------------------------------------------------------------------ Total revenues from sales of electricity 779,428 672,397 619,884 582,077 532,526 Other revenues 16,637 15,205 13,120 13,054 11,062 ------------------------------------------------------------------------------------------------------------------------------------ Total $796,065 $687,602 $633,004 $595,131 $543,588 ==================================================================================================================================== Kilowatt-Hour Sales (in thousands)*: Residential 2,162,623 2,286,143 2,248,255 2,248,915 2,039,042 Commercial 2,840,840 2,883,197 2,847,342 2,623,276 2,407,520 Industrial 4,275,781 4,376,171 4,407,445 3,729,166 3,981,875 Other 41,009 41,153 40,091 39,772 40,508 ------------------------------------------------------------------------------------------------------------------------------------ Total retail 9,320,253 9,586,664 9,543,133 8,641,129 8,468,945 Sales for resale - non-affiliates 5,011,212 3,674,621 3,256,175 3,157,837 2,895,182 Sales for resale - affiliates 2,952,455 452,611 539,939 552,142 478,884 ------------------------------------------------------------------------------------------------------------------------------------ Total 17,283,920 13,713,896 13,339,247 12,351,108 11,843,011 ==================================================================================================================================== Average Revenue Per Kilowatt-Hour (cents)*: Residential 7.62 7.47 7.11 7.01 6.80 Commercial 5.75 5.67 5.41 5.55 5.57 Industrial 3.66 3.65 3.43 3.62 3.52 Total retail 5.25 5.20 4.92 5.12 4.93 Sales for resale 3.64 4.21 3.96 3.76 3.42 Total sales 4.51 4.90 4.65 4.71 4.50 Residential Average Annual Kilowatt-Hour Use Per Customer * 13,634 14,445 14,301 14,376 13,132 Residential Average Annual Revenue Per Customer * $1,038.41 $1,078.76 $1,017.42 $1,007.68 $892.68 Plant Nameplate Capacity Ratings (year-end) (megawatts) 3,156 2,086 2,086 2,086 2,086 Maximum Peak-Hour Demand (megawatts): Winter 2,249 2,305 2,125 1,740 1,922 Summer 2,466 2,593 2,439 2,339 2,209 Annual Load Factor (percent) 60.7 59.3 59.6 58.0 59.1 Plant Availability Fossil-Steam (percent): 92.8 92.6 91.0 90.0 92.4 ------------------------------------------------------------------------------------------------------------------------------------ Source of Energy Supply (percent): Coal 52.0 67.8 69.4 66.5 70.5 Oil and gas 35.9 13.5 15.9 14.5 12.5 Purchased power - From non-affiliates 3.1 7.7 6.2 8.0 3.0 From affiliates 9.0 11.0 8.5 11.0 14.0 ------------------------------------------------------------------------------------------------------------------------------------ Total 100.0 100.0 100.0 100.0 100.0 ==================================================================================================================================== * 1999 data includes the true-up of the unbilled revenue estimates.
II-179 SAVANNAH ELECTRIC AND POWER COMPANY FINANCIAL SECTION II-180 MANAGEMENT'S REPORT Savannah Electric and Power Company 2001 Annual Report The management of Savannah Electric and Power Company has prepared--and is responsible for--the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements. The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship. The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. The audit committee of the board of directors, composed of five independent directors who are not employees, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls and financial reporting matters. The internal auditors and the independent public accountants have access to the members of the audit committee at any time. Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics. In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Savannah Electric and Power Company in conformity with accounting principles generally accepted in the United States. /s/Anthony R. James Anthony R. James President and Chief Executive Officer /s/K.R. Willis K. R. Willis Vice President, Treasurer, Chief Financial Officer and Assistant Secretary February 13, 2002 II-181 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Savannah Electric and Power Company: We have audited the accompanying balance sheets and statements of capitalization of Savannah Electric and Power Company (a Georgia corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements (pages II-192 through II-206) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2001, Savannah Electric and Power Company changed its method of accounting for derivative instruments and hedging activities. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 II-182 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 2001 Annual Report RESULTS OF OPERATIONS --------------------- Earnings Savannah Electric and Power Company's net income for 2001 totaled $22.1 million, representing a decrease of $0.9 million or 3.9 percent from the prior year. Earnings were down primarily due to lower retail revenues. In 2000, earnings were $23.0 million, representing no significant change from the prior year. Revenues Total operating revenues for 2001 were $283.9 million, reflecting a 4.0 percent decrease when compared to 2000. The following table summarizes the factors affecting operating revenues for the past two years: Increase (Decrease) Amount From Prior Year -------------------------------------- 2001 2001 2000 -------------------------------------- (in thousands) Retail -- Base Revenues $159,839 $ (1,968) $9,272 Fuel cost recovery and other 109,333 (11,482) 31,085 ----------------------------------------------------------------- Total retail 269,172 (13,450) 40,357 ----------------------------------------------------------------- Sales for resale -- Non-affiliates 8,884 4,136 1,353 Affiliates 3,205 (1,769) 823 ----------------------------------------------------------------- Total sales for resale 12,089 2,367 2,176 ----------------------------------------------------------------- Other operating revenues 2,591 (783) 1,591 ----------------------------------------------------------------- Total operating revenues $283,852 $(11,866) $44,124 ================================================================= Percent change (4.0)% 17.5% ----------------------------------------------------------------- Retail revenues decreased 4.8 percent or $13.5 million in 2001 as compared to 2000. The primary contributors to the decrease were the negative impact of mild weather on energy sales and a decrease in fuel revenues, partially due to a lower average cost of fuel consumed. Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under these fuel recovery provisions, fuel revenues generally equal fuel expenses--including the fuel component of purchased energy--and do not affect net income. However, cash flow is affected by the economic loss from untimely recovery of these receivables. In May 2001, the Company implemented a Fuel Cost Recovery (FCR) rate increase under a Georgia Public Service Commission (GPSC) rate order. The order established a new fuel rate to better reflect current fuel costs and to collect the under-recovered balance. The GPSC-approved FCR anticipated a three year recovery of the under-recovered fuel balance. Due to the current year decreases in fuel costs, the Company recovered approximately 70 percent of this balance by year-end 2001. Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. These transactions do not have a significant impact on earnings. Sales to affiliated companies within the Southern electric system vary from year to year depending on demand and the availability and cost of generating resources at each company. These energy sales do not have a significant impact on earnings. Energy Sales Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as follows: KWH Percent Change ------------- ------------------- 2001 2001 2000 ------------- ------------------- (in millions) Residential 1,659 (0.7)% 5.8% Commercial 1,388 1.4 6.3 Industrial 788 (1.6) 12.2 Other 134 (1.4) 2.5 ------------- Total retail 3,969 (0.2) 7.1 Sales for resale -- Non-affiliates 111 43.4 50.3 Affiliates 88 (1.0) 15.1 ------------- Total 4,168 0.6% 7.8% =========================================================== Total retail energy sales in 2001 decreased slightly from the prior year. Residential sales decreased reflecting mild weather, somewhat offset by continued growth in customers. Industrial sales decreased reflecting a slowing of the economy. Commercial energy sales increased 1.4 percent reflecting continued customer growth. II-183 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report In 2000, total retail energy sales were up by 7.1 percent from the prior year, reflecting increased energy sales of 12.2 percent to industrial customers due to the re-opening of an industrial facility under new ownership. Residential and commercial energy sales also increased reflecting weather related demand and customer growth. Expenses Total operating expenses for 2001 were $234.3 million, a decrease of $9.0 million from the prior year due primarily to decreases in fuel expense and purchased power from both affiliates and non-affiliates. The decrease in fuel expense is attributable to a decrease in generation and lower fuel costs. Purchased power decreased due principally to lower energy costs. Other operation expense was lower reflecting decreased costs associated with discontinuation of a marketing program and lower administrative and general expenses. Maintenance expense increased from 2000 reflecting higher power delivery costs to support improved customer reliability. In 2000, total operating expenses were $243.3 million, an increase of $41.8 million from the prior year. This increase was due primarily to increases in purchased power from both affiliates and non-affiliates and fuel expense. Purchased power increased due principally to higher energy costs. Other operation expense was higher reflecting increased benefit expenses. Maintenance expense increased from 1999 reflecting higher power delivery and power generation maintenance costs to support improved customer reliability and unit availability, respectively. Depreciation and amortization increased reflecting additional depreciation charges related to the GPSC accounting order. See Note 3 to the financial statements for additional information on the GPSC's 1998 accounting order. Fuel and purchased power costs constitute the single largest expense for the Company. The mix of energy supply is determined primarily by system load, the unit cost of fuel consumed, and the availability of units. The amount and sources of energy supply and the total average cost of energy supply were as follows: 2001 2000 1999 -------------------------- Total energy supply (millions of KWHs) 4,310 4,286 4,039 Sources of energy supply (percent) -- Coal 50 52 45 Oil 1 2 2 Gas 3 5 10 Purchased Power 46 41 43 Total average cost of energy supply (cents) 2.87 3.09 2.44 ----------------------------------------------------------------- Effects of Inflation The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and trust preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed. Future Earnings Potential General The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors ranging from energy sales growth to a less regulated, more competitive environment. Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new short and long-term contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area. II-184 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report The Company currently operates as a vertically integrated utility providing electricity to customers within the traditional service area of southeastern Georgia. Prices for electricity provided by the Company to retail customers are set by the GPSC. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the Federal Energy Regulatory Commission (FERC). As part of the Company's retail rate settlement in 1992, it was informally agreed that the Company's earned rate of return on common equity should be 12.95 percent. In 1998, the GPSC issued a four-year accounting order settling its review of the Company's earnings. See Note 3 to the financial statements for additional information. Southern Power Company, a new Southern Company affiliate formed in 2001 to construct, own, and manage wholesale generating assets in the Southeast, is currently constructing two 566 megawatt combined cycle units at Plant Wansley to begin operation in 2002. The GPSC has certified the Company's purchase of 200 megawatts of capacity from these units to serve its retail customers for approximately seven years. The Company filed a base rate case on November 30, 2001 for the first time since 1985. The primary reason for this base rate case is to recover significant new costs related to the Plant Wansley power purchase agreement beginning June 2002, as well as other operation and maintenance expense changes. The requested increase is 7.6 percent of total rates (base plus fuel). In the filing, the Company announced it would file for a fuel decrease in early 2002 to offset most, if not all, of the base rate increase. The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings. Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed under "Environmental Matters." Industry Restructuring The electric utility industry in the United States is currently undergoing a period of dramatic change as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access the Company's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While the GPSC has held workshops to discuss retail competition and industry restructuring, there has been no proposed or enacted legislation to date in Georgia. Enactment would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California. As a result of that crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. The Company does compete with other electric suppliers within the state. In Georgia, most new retail customers with at least 900 kilowatts of connected load may choose their electricity supplier. In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its operating companies, including the Company, have submitted a series of status reports informing the II-185 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In January 2002, the sponsors of SeTrans held a public meeting to form a Stakeholder Advisory Committee, which will participate in the development of the RTO. Southern Company continues to work with the other sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to have a material impact on Southern Company's financial statements. The outcome of this matter cannot now be determined. Accounting Policies Critical Policy The Company's significant accounting policies are described in Note 1 to the financial statements. The Company's most critical accounting policy involves rate regulation. The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information. New Accounting Standards Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Statement No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value, and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. See Note 1 to the financial statements under "Financial Instruments" for additional information. The impact on net income in 2001 was not material. An additional interpretation of Statement No. 133 will result in a change -- effective April 1, 2002 -- in accounting for certain contracts related to fuel supplies that contain quantity options. These contracts will be accounted for as derivatives and marked to market. However, due to the existence of the Company's cost-based fuel recovery clause, this change is not expected to have a material impact on net income. On June 1, 2001, the Company implemented a natural gas/oil hedging program which was ordered by the GPSC as part of the fuel cost recovery increase filing. The maximum annual dollar amount of the hedges recoverable through the fuel cost recovery clause is 10 percent of the annual gas/oil budget or $1.5 million for 2001 and $2.4 million for 2002. In June 2001, the FASB issued Statement No. 142, Goodwill and Other Intangible Assets, which establishes new accounting and reporting standards for acquired goodwill and other intangible assets and supersedes Accounting Principles Board Opinion No. 17. Statement No. 142 addresses how intangible assets that are acquired individually or with a group of other assets -- but not those acquired in a business combination -- should be accounted for upon acquisition and on an ongoing basis. Goodwill and intangible assets that have indefinite useful lives will not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives, which are no longer limited to 40 years. The Company adopted Statement No. 142 in January 2002 with no material impact on the financial statements. Also in June 2001, the FASB issued Statement No. 143, Asset Retirement Obligations, which establishes new accounting and reporting standards for legal obligations associated with retiring assets, including decommissioning of nuclear plants. The liability for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The Company has not yet quantified the impact of adopting Statement No. 143 on its financial statements. II-186 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report FINANCIAL CONDITION ------------------- Overview The principal change in the Company's financial condition in 2001 was the addition of $31.3 million to utility plant. The funds needed for gross property additions are currently provided from operating activities, principally from earnings, and non-cash charges to income such as depreciation and deferred income taxes and from financing activities. See Statements of Cash Flows for additional information. Credit Rating Risk The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. Exposure to Market Risks Due to cost-based regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. At December 31, 2001, exposure from these activities was not material to the Company's financial statements. Also, if the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $0.2 million at December 31, 2001. Fair values of changes in energy trading contracts and year-end valuations are as follows: Changes During the Year ------------------- Fair Value -------------------------------------------------------------- (in thousands) Contracts beginning of year $ 36 Contracts realized or settled (32) New contracts at inception - Changes in valuation techniques - Current period changes (1,057) -------------------------------------------------------------- Contracts end of year $(1,053) ============================================================== Source of Year-End Valuation Prices --------------------------------- Maturity Total -------------------- Fair Value Year 1 1-3 Years --------------------------------------------------------------- (in thousands) --------------------------------------------------------------- Actively quoted $(1,053) $(1,051) $(2) External sources - - - Models and other methods - - - --------------------------------------------------------------- Contracts end of Year $(1,053) $(1,051) $(2) =============================================================== For additional information, see Note 1 to the financial statements under "Financial Instruments." Capital Structure As of December 31, 2001, the Company's capital structure consisted of 46.8 percent common stockholder's equity, 10.6 percent trust preferred securities, and 42.6 percent long-term debt, excluding amounts due within one year. Maturities and retirements of long-term debt were $50.7 million in 2001, $0.4 million in 2000, and $16.2 million in 1999. In May 2001, the Company issued $20 million of series B 5.12% senior notes maturing in 2003 and $45 million of series C 6.55% senior notes maturing in 2008. The Company used these proceeds to redeem its $20 million 6 3/8 Series First Mortgage Bonds due in 2003, to repay long-term bank loans in the amount of $30 million, and to repay a portion of its short-term indebtedness. The composite interest rates and dividend rates for the years 1999 through 2001 as of year-end were as follows: 2001 2000 1999 ------------------------------- Composite interest rates on long-term debt 5.9% 6.6% 6.4% Trust preferred securities dividend rate 6.9% 6.9% 6.9% ----------------------------------------------------------------- Capital Requirements for Construction The Company's projected construction expenditures for the next three years total $115.7 million ($34.8 million in 2002, $37.6 million in 2003, and $43.3 million in 2004). Actual construction costs may vary from this estimate because of II-187 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report factors such as changes in: business conditions; environmental regulations; load projections; the cost and efficiency of construction labor, equipment and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Construction and upgrading of new and existing transmission and distribution facilities and upgrading of generating plants will be continuing. Other Capital Requirements In addition to the funds needed for the construction program, approximately $22.5 million will be needed by the end of 2004 for maturities of long-term debt and present sinking fund requirements. Capital requirements, lease obligations, and purchase commitments - discussed in Notes 4 and 6 to the financial statements -- are as follows: 2002 2003 2004 ------------------------------------------------------------ (in thousands) Notes $ - $20,000 $ - Bonds - First mortgage 436 - - Pollution control - - - Leases - Capital 742 688 627 Operating 429 429 429 Purchase commitments Fuel 34,000 300 300 Purchased power 9,944 13,640 13,656 ------------------------------------------------------------- Credit arrangements at the beginning of 2002, are as follows: Expires --------------------------------- Total 2002 2003 --------------------------------------------------------- (in thousands) $65,500 $45,500 $20,000 ---------------------------------------------------------- For additional information, see Note 6 to the financial statements under "Bank Credit Arrangements". Environmental Matters On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to Southern Company's operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously and the Company's Plant Kraft. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court granted the EPA's motion to add the Company as a defendant, but it denied the motion to add Gulf Power and Mississippi Power based on lack of jurisdiction over those companies. The court directed the EPA to re-file its amended complaint limiting claims to those brought against Georgia Power and the Company. The EPA re-filed those claims as directed by the court. Also, the EPA re-filed its claims against Alabama Power in U.S. District Court in Alabama. It has not re-filed against Gulf Power, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and the Company's cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and the Company. Because the outcome of II-188 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report the TVA case could have a significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and the Company have opposed that motion. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were signed into law. Title IV of the Clean Air Act--the acid rain compliance provision of the law--significantly affected the Company and other subsidiaries of Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995. Southern Company's subsidiaries, including the Company, achieved Phase I compliance at the affected plants by primarily switching to low-sulfur coal and with some equipment upgrades. The construction expenditures for Phase I compliance totaled approximately $2 million for the Company. Phase II sulfur dioxide compliance was required in 2000. Southern Company used emission allowances and fuel switching to comply with Phase II requirements. Phase II compliance had no significant impact on the Company. A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered. In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals is considering other legal challenges to these standards. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued regional nitrogen oxide reduction rules to the states for implementation. The final rule affects 21 states, including Georgia. Compliance is required by May 31, 2004 for most states. For Georgia, further rulemaking was required, and proposed compliance was delayed until May 1, 2005. In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act, and the regulations are scheduled to be finalized by the end of 2004 with implementation to take place around 2007. In January 2001, the EPA proposed guidance for the determination of Best Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls is expected to take place around 2010. Litigation of the Regional Haze Regulations, including the BART provisions, is ongoing in the Federal District of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002. Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide and reductions in mercury and other HAPS emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. II-189 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report In October 1997, the EPA issued regulations setting forth requirements for Compliance Assurance Monitoring (CAM) in its state and federal operating permit programs. These regulations were amended by the EPA in March 2001 in response to a court order resolving challenges to the rules brought by environmental groups and industry. Generally, this rule affects the operation and maintenance of electrostatic precipitators and could involve significant additional ongoing expense. The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and will recognize in the financial statements costs to clean up known sites. Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect the Company. The impact of new legislation--if any--will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields. Sources of Capital At December 31, 2001, the Company had $65.5 million of short-term and revolving credit arrangements with banks to meet its short-term cash needs and to provide additional interim funding for the Company's construction program. Revolving credit arrangements total $20 million, of which $10 million expires April 30, 2003 and $10 million expires December 31, 2003. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company operating companies. At December 31, 2001, the Company had outstanding $32.2 million of commercial paper. The Company's committed credit arrangements provide liquidity support to the Company's variable rate obligations and to its commercial paper program. The amount of variable rate obligations outstanding at December 31, 2001 was $22.6 million. It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived from sources similar to those used in the past. These sources were primarily from the issuances of first mortgage bonds, other long-term debt, and preferred stock, in addition to pollution control revenue bonds issued for the Company's benefit by public authorities, to meet long-term external financing requirements. Recently, the Company's financings have consisted of unsecured debt and trust preferred securities. The Company is required to meet certain earnings coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's coverage ratios are sufficiently high to permit, at present interest rate levels, any foreseeable security sales. There are no restrictions on the amount of unsecured indebtedness allowed. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time. II-190 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2001 Annual Report Cautionary Statement Regarding Forward-Looking Information This Annual Report includes forward-looking statements in addition to historical information. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "could," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "projects," "potential" or "continue" or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental 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, including the pending EPA civil action against the Company; the effects, extent, and timing of the entry of additional competition in the markets of the Company; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; 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; the effects of, and changes in, economic conditions in the United States; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission. II-191
STATEMENTS OF INCOME For the Years Ended December 31, 2001, 2000, and 1999 Savannah Electric and Power Company 2001 Annual Report --------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Revenues: Retail sales $269,172 $282,622 $242,265 Sales for resale -- Non-affiliates 8,884 4,748 3,395 Affiliates 3,205 4,974 4,151 Other revenues 2,591 3,374 1,783 --------------------------------------------------------------------------------------------------------------------- Total operating revenues 283,852 295,718 251,594 --------------------------------------------------------------------------------------------------------------------- Operating Expenses: Operation -- Fuel 50,796 57,177 50,530 Purchased power -- Non-affiliates 23,147 25,229 14,398 Affiliates 49,939 50,111 33,398 Other 50,607 53,086 50,341 Maintenance 19,886 19,334 16,333 Depreciation and amortization (Note 3) 25,951 25,240 23,841 Taxes other than income taxes 13,984 13,116 12,690 --------------------------------------------------------------------------------------------------------------------- Total operating expenses 234,310 243,293 201,531 --------------------------------------------------------------------------------------------------------------------- Operating Income 49,542 52,425 50,063 Other Income (Expense): Interest income 173 252 169 Other, net (686) (657) (663) --------------------------------------------------------------------------------------------------------------------- Earnings Before Interest and Income Taxes 49,029 52,020 49,569 --------------------------------------------------------------------------------------------------------------------- Interest and Other: Interest expense, net 12,517 12,737 11,938 Distributions on preferred securities of subsidiary 2,740 2,740 2,740 --------------------------------------------------------------------------------------------------------------------- Total interest and other, net 15,257 15,477 14,678 --------------------------------------------------------------------------------------------------------------------- Earnings Before Income Taxes 33,772 36,543 34,891 Income taxes (Note 5) 11,731 13,574 11,808 --------------------------------------------------------------------------------------------------------------------- Earnings Before Cumulative Effect of 22,041 22,969 23,083 Accounting Change Cumulative effect of accounting change-- less income taxes of $14 thousand 22 - - --------------------------------------------------------------------------------------------------------------------- Net Income $ 22,063 $ 22,969 $ 23,083 ===================================================================================================================== The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001, 2000, and 1999 Savannah Electric and Power Company 2001 Annual Report --------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Activities: Net income $22,063 $22,969 $23,083 Adjustments to reconcile net income to net cash provided from operating activities -- Depreciation and amortization 27,895 26,639 25,454 Deferred income taxes and investment tax credits, net (20,528) 728 (3,353) Other, net 4,084 3,835 (47) Changes in certain current assets and liabilities -- Receivables, net 24,079 (23,260) (5,999) Fossil fuel stock (2,711) (31) (2,125) Materials and supplies (4,025) (542) (1,906) Accounts payable (8,439) 8,881 1,133 Other 12,631 (4,674) 1,731 --------------------------------------------------------------------------------------------------------------------------- Net cash provided from operating activities 55,049 34,545 37,971 --------------------------------------------------------------------------------------------------------------------------- Investing Activities: Gross property additions (31,296) (27,290) (29,833) Other (1,875) (1,835) (1,715) --------------------------------------------------------------------------------------------------------------------------- Net cash used for investing activities (33,171) (29,125) (31,548) --------------------------------------------------------------------------------------------------------------------------- Financing Activities: Increase (decrease) in notes payable, net (13,241) 11,100 34,300 Proceeds -- Other long-term debt 65,000 - - Capital contributions from parent company 1,561 1,478 1,099 Retirements -- First mortgage bonds (20,642) - (15,800) Other long-term debt (30,071) (251) (481) Payment of common stock dividends (21,700) (24,300) (25,200) Other (394) - 250 --------------------------------------------------------------------------------------------------------------------------- Net cash used for financing activities (19,487) (11,973) (5,832) --------------------------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents 2,391 (6,553) 591 Cash and Cash Equivalents at Beginning of Period - 6,553 5,962 --------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 2,391 $ - $ 6,553 =========================================================================================================================== Supplemental Cash Flow Information: Cash paid during the period for -- Interest (net of amount capitalized) $15,340 $13,329 $14,212 Income taxes (net of refunds) $21,034 $19,939 $12,647 --------------------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of these statements.
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BALANCE SHEETS At December 31, 2001 and 2000 Savannah Electric and Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------- Assets 2001 2000 ----------------------------------------------------------------------------------------------------------------------- (in thousands) Current Assets: Cash and cash equivalents $ 2,391 $ - Receivables -- Customer accounts receivable 29,959 28,189 Under-recovered retail fuel clause revenue 11,974 39,632 Other accounts and notes receivable 2,882 1,412 Affiliated companies 1,170 738 Accumulated provision for uncollectible accounts (500) (407) Fossil fuel stock, at average cost 9,851 7,140 Materials and supplies, at average cost 12,969 8,944 Prepaid taxes 12,511 8,651 Other 586 377 ----------------------------------------------------------------------------------------------------------------------- Total current assets 83,793 94,676 ----------------------------------------------------------------------------------------------------------------------- Property, Plant, and Equipment: In service (Note 6) 855,290 829,270 Less accumulated provision for depreciation 402,492 382,030 ----------------------------------------------------------------------------------------------------------------------- 452,798 447,240 Construction work in progress 8,540 6,782 ----------------------------------------------------------------------------------------------------------------------- Total property, plant, and equipment 461,338 454,022 ----------------------------------------------------------------------------------------------------------------------- Other Property and Investments 2,742 2,066 ----------------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets: Deferred charges related to income taxes (Note 5) 12,283 12,404 Cash surrender value of life insurance for deferred compensation plans 20,002 17,954 Debt expense, being amortized 3,197 3,003 Premium on reacquired debt, being amortized 6,890 7,575 Other 4,498 2,527 ----------------------------------------------------------------------------------------------------------------------- Total deferred charges and other assets 46,870 43,463 ----------------------------------------------------------------------------------------------------------------------- Total Assets $594,743 $594,227 ======================================================================================================================= The accompanying notes are an integral part of these balance sheets.
II-194
BALANCE SHEETS At December 31, 2001 and 2000 Savannah Electric and Power Company 2001 Annual Report -------------------------------------------------------------------------------------------------------------------- Liabilities and Stockholder's Equity 2001 2000 -------------------------------------------------------------------------------------------------------------------- (in thousands) Current Liabilities: Securities due within one year (Note 6) $ 1,178 $ 30,698 Notes payable 32,159 45,400 Accounts payable -- Affiliated 5,087 16,153 Other 10,160 7,738 Customer deposits 6,237 5,696 Taxes accrued -- Income taxes 2,587 3,450 Other 1,668 1,435 Interest accrued 4,014 4,541 Vacation pay accrued 2,361 2,276 Other 9,097 7,973 -------------------------------------------------------------------------------------------------------------------- Total current liabilities 74,548 125,360 -------------------------------------------------------------------------------------------------------------------- Long-term debt (See accompanying statements) 160,709 116,902 -------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes (Note 5) 77,331 79,756 Deferred credits related to income taxes (Note 5) 13,776 16,038 Accumulated deferred investment tax credits (Note 5) 9,952 10,616 Deferred compensation plans 8,550 7,695 Employee benefits provisions (Note 2) 18,936 13,509 Other 14,023 9,357 -------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 142,568 136,971 -------------------------------------------------------------------------------------------------------------------- Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding company junior subordinated notes (See accompanying statements) (Note 6) 40,000 40,000 -------------------------------------------------------------------------------------------------------------------- Common stockholder's equity (See accompanying statements) 176,918 174,994 -------------------------------------------------------------------------------------------------------------------- Total Liabilities and Stockholder's Equity $594,743 $594,227 ==================================================================================================================== The accompanying notes are an integral part of these balance sheets.
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STATEMENTS OF CAPITALIZATION At December 31, 2001 and 2000 Savannah Electric and Power Company 2001 Annual Report --------------------------------------------------------------------------------------------------------------------------- 2001 2000 2001 2000 --------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Long-Term Debt (Note 6): First mortgage bonds -- Maturity Interest Rates -------- -------------- July 1, 2003 6.375% $ - $ 20,000 May 1, 2006 6.90% 20,000 20,000 July 1, 2023 7.40% 23,558 24,200 --------------------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 43,558 64,200 --------------------------------------------------------------------------------------------------------------------------- Long-term notes payable -- 6.88% due June 1, 2001 - 10,000 5.12% due May 15, 2003 20,000 - 6.55% due May 15, 2008 45,000 - 6.625% due March 17, 2015 30,000 30,000 Adjustable rates (6.71% to 6.86% at 1/1/01) due 2001 - 20,000 --------------------------------------------------------------------------------------------------------------------------- Total long-term notes payable 95,000 60,000 --------------------------------------------------------------------------------------------------------------------------- Other long-term debt -- Pollution control revenue bonds -- Non-collateralized: Variable rates (1.90% at 1/1/02) due 2016-2037 17,955 17,955 --------------------------------------------------------------------------------------------------------------------------- Total other long-term debt 17,955 17,955 --------------------------------------------------------------------------------------------------------------------------- Capitalized lease obligations 5,374 5,445 --------------------------------------------------------------------------------------------------------------------------- Total long-term debt (annual interest requirement -- $9.6 million) 161,887 147,600 Less amount due within one year (Note 6) 1,178 30,698 --------------------------------------------------------------------------------------------------------------------------- Long-term debt excluding amount due within one year 160,709 116,902 42.6% 35.2% --------------------------------------------------------------------------------------------------------------------------- Company Obligated Mandatorily Redeemable Preferred Securities (Note 6): $25 liquidation value -- 6.85% 40,000 40,000 --------------------------------------------------------------------------------------------------------------------------- Total (annual distribution requirement -- $2.7 million) 40,000 40,000 10.6 12.1 --------------------------------------------------------------------------------------------------------------------------- Common Stockholder's Equity (Note 6): Common stock, par value $5 per share -- Authorized - 16,000,000 shares Outstanding - 10,844,635 shares in 2001 and 2000 Par value 54,223 54,223 Paid-in capital 12,826 11,265 Retained earnings 109,869 109,506 --------------------------------------------------------------------------------------------------------------------------- Total common stockholder's equity 176,918 174,994 46.8 52.7 --------------------------------------------------------------------------------------------------------------------------- Total Capitalization $377,627 $331,896 100.0% 100.0% =========================================================================================================================== The accompanying notes are an integral part of these statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2001, 2000, and 1999 Savannah Electric and Power Company 2001 Annual Report ---------------------------------------------------------------------------------------------------------------------- Common Paid-In Retained Stock Capital Earnings Total ---------------------------------------------------------------------------------------------------------------------- (in thousands) Balance at January 1, 1999 $54,223 $ 8,688 $112,954 $175,865 Net income - - 23,083 23,083 Capital contributions from parent company - 1,099 - 1,099 Cash dividends on common stock - - (25,200) (25,200) ---------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 54,223 9,787 110,837 174,847 Net income - - 22,969 22,969 Capital contributions from parent company - 1,478 - 1,478 Cash dividends on common stock - - (24,300) (24,300) ---------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 54,223 11,265 109,506 174,994 Net income - - 22,063 22,063 Capital contributions from parent company - 1,561 - 1,561 Cash dividends on common stock - - (21,700) (21,700) ---------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 (Note 6) $54,223 $12,826 $109,869 $176,918 ====================================================================================================================== The accompanying notes are an integral part of these statements.
II-197 NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 2001 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Savannah Electric and Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern LINC), Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern Power), and other direct and indirect subsidiaries. The operating companies provide electric service in four states. Contracts among the operating companies--related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company also is subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by the GPSC. 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. Certain prior years' data presented in the financial statements has been reclassified to conform with the current year presentation. Affiliate Transactions The Company has an agreement with the system service company under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and employee benefits, human resources, systems and procedures, and other administrative services with respect to business and operations and power pool operations. Costs for these services amounted to $15.0 million, $15.1 million, and $16.0 million during 2001, 2000, and 1999, respectively. Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to: 2001 2000 -------------------------- (in thousands) Deferred income tax charges $ 12,283 $ 12,404 Premium on reacquired debt 6,890 7,575 Gas by-pass facility 209 299 Deferred income tax credits (13,776) (16,038) Storm damage reserves (4,228) (2,733) Accelerated depreciation (8,000) (5,500) --------------------------------------------------------------- Total $ (6,622) $ (3,993) =============================================================== In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value. Revenues and Fuel Costs The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia and to wholesale customers in the Southeast. II-198 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current regulated rates. The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than 1 percent of revenues. In 2001, the GPSC approved an increase in the Company's fuel cost recovery rate amounting to a total average annual rate increase of 18 percent for all customer classes. An increase of slightly over one-third of a cent per kilowatt-hour was approved in 2000. Depreciation and Amortization Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.0 percent in 2001, 2000, and 1999. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost--together with the cost of removal, less salvage--is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of certain facilities. In 2001, 2000, and 1999, the Company recorded accelerated depreciation of $2.5 million, $2.5 million, and $2.0 million, respectively, in accordance with the GPSC's 1998 rate order. See Note 3 to the financial statements for more information. Income Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property. Allowance for Funds Used During Construction (AFUDC) AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rates used by the Company to calculate AFUDC were 5.13 percent in 2001, 6.87 percent in 2000, and 6.26 percent in 1999. 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 AFUDC. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property exclusive of minor items of property is capitalized. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Financial Instruments Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The impact on net income was immaterial. The Company uses derivative financial instruments to hedge exposure to fluctuations in certain commodity prices. Gains and losses on qualifying hedges are deferred and recognized either as income or as an adjustment to the carrying amount of the hedged item when the transaction occurs. II-199 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report 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 five operating companies and Southern Power enter into commodity related forward and option contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of Southern Company's bulk energy purchases and sales contracts meet the definition of a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. In many cases, these fuel and electricity contracts qualify for normal purchase and sale exceptions under Statement No. 133 and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses, and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income. On June 1, 2001, the Company implemented a natural gas/oil hedging program which was ordered by the GPSC as part of the fuel cost recovery increase filing. The maximum annual dollar amount of the hedges recoverable through the fuel cost recovery clause is 10 percent of the annual gas/oil budget or $1.5 million for 2001 and $2.4 million for 2002. The Company's other financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows: Carrying Fair Amount Value -------------------------- (in millions) Long-term debt: At December 31, 2001 $157 $157 At December 31, 2000 $142 $140 Trust preferred securities: At December 31, 2001 $40 $38 At December 31, 2000 $40 $36 The fair values for long-term debt and trust preferred securities were based on either closing market prices or closing prices of comparable instruments. 2. RETIREMENT BENEFITS The Company has defined benefit, trusteed, non-contributory pension plans that cover substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to the extent required by the GPSC and the FERC. The measurement date for plan assets and obligations is September 30 of each year. In late 2000, the Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees. Pension Plans Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations --------------------------- 2001 2000 --------------------------------------------------------------- (in thousands) Balance at beginning of year $71,521 $66,509 Service cost 2,074 1,844 Interest cost 5,426 4,854 Benefits paid (3,986) (3,469) Actuarial loss and employee transfers 894 1,564 Amendments 3,621 219 --------------------------------------------------------------- Balance at end of year $79,550 $71,521 =============================================================== Plan Assets --------------------------- 2001 2000 --------------------------------========================------- (in thousands) Balance at beginning of year $61,880 $54,480 Actual return on plan assets (8,911) 10,493 Benefits paid (3,570) (3,210) Employee transfers 1,459 117 ---------------------------------====================---------- Balance at end of year $50,858 $61,880 =============================================================== II-200 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report The accrued pension costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------- (in thousands) Funded status $(28,692) $(9,641) Unrecognized transition obligation - 89 Unrecognized prior service cost 7,401 4,391 Unrecognized net loss (gain) 12,336 (235) --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (8,955) $(5,396) =============================================================== Components of the pension plan's net periodic cost were as follows: 2001 2000 1999 ----------------------------------------------------------------- (in thousands) Service cost $ 2,074 $ 1,844 $ 1,838 Interest cost 5,426 4,854 4,327 Expected return on plan assets (4,215) (4,174) (4,063) Recognized net loss 16 - 171 Net amortization 700 503 478 ----------------------------------------------------------------- Net pension cost $ 4,001 $ 3,027 $ 2,751 ================================================================= Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations --------------------------- 2001 2000 --------------------------------------------------------------- (in thousands) Balance at beginning of year $26,124 $22,904 Service cost 433 376 Interest cost 2,022 1,865 Benefits paid (987) (963) Actuarial gain and employee transfers (1,214) (1,367) Amendments 1,743 3,309 --------------------------------------------------------------- Balance at end of year $28,121 $26,124 =============================================================== Plan Assets --------------------------- 2001 2000 --------------------------------------------------------------- (in thousands) Balance at beginning of year $6,910 $5,254 Actual return on plan assets (789) 606 Employer contributions 2,267 2,013 Benefits paid (987) (963) --------------------------------------------------------------- Balance at end of year $7,401 $6,910 =============================================================== The accrued postretirement costs recognized in the Balance Sheets were as follows: 2001 2000 --------------------------------------------------------------- (in thousands) Funded status $(20,720) $(19,214) Unrecognized transition obligation 5,431 5,925 Unamortized prior service cost 4,691 3,185 Unrecognized net loss 1,831 1,701 Fourth quarter contributions 1,577 1,493 --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (7,190) $ (6,910) =============================================================== Components of the postretirement plan's net periodic cost were as follows: 2001 2000 1999 ---------------------------------------------------------------- (in thousands) Service cost $ 433 $ 376 $ 404 Interest cost 2,022 1,865 1,549 Expected return on plan assets (555) (429) (345) Recognized net loss - 66 152 Net amortization 731 618 494 ---------------------------------------------------------------- Net postretirement cost $2,631 $2,496 $2,254 ================================================================ The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits plan were: 2001 2000 ------------------------------------------------------------- Discount 7.50% 7.50% Annual salary increase 5.00 5.00 Long-term return on plan assets 8.50 8.50 ------------------------------------------------------------- An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 9.25 percent for 2001, decreasing gradually to 5.25 percent through the year 2010, and remaining at that level thereafter. An annual increase or decrease in the II-201 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2001 as follows: 1 Percent 1 Percent Increase Decrease --------------------------------------------------------------- (in thousands) Benefit obligation $2,070 $2,051 Service and interest costs 181 179 =============================================================== The Company has a supplemental retirement plan for certain executive employees. The plan is unfunded and payable from the general funds of the Company. The Company has purchased life insurance on participating executives and plans to use these policies to satisfy this obligation. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2001, 2000, and 1999 were $1.0 million, $0.9 million, and $0.9 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General The Company is subject to certain claims and legal actions arising in the ordinary course of business. In the opinion of management, after consultation with legal counsel, the ultimate disposition of these matters is not expected to have a material adverse effect on the Company's financial condition. Environmental Litigation On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously and the Company's Plant Kraft. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. The court granted the EPA's motion to add the Company as a defendant, but it denied the motion to add Gulf Power and Mississippi Power based on lack of jurisdiction over those companies. The court directed the EPA to re-file its amended complaint limiting claims to those brought against Georgia Power and the Company. The EPA re-filed those claims as directed by the court. Also, the EPA re-filed its claims against Alabama Power in U.S. District Court in Alabama. It has not re-filed against Gulf Power, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and the Company's cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and the Company. Because the outcome of the TVA case could have a II-202 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report significant adverse impact on Alabama Power and Georgia Power, both companies are parties to that case as well. The U.S. District Court in Alabama has indicated that it will revisit the issue of a continued stay in April 2002. The U.S. District Court in Georgia is currently considering a motion by the EPA to reopen the Georgia case. Georgia Power and the Company have opposed that motion. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. Retail Regulatory Matters Rates to retail customers served by the Company are regulated by the GPSC. As part of the Company's rate settlement in 1992, it was informally agreed that the Company's earned rate of return on common equity should be 12.95 percent. In 1998, the GPSC approved a four-year accounting order for the Company. Under this order, the Company will reduce the electric rates of its small business customers by approximately $11 million over four years. The Company will also expense an additional $1.95 million in storm damage accruals and accrue an additional $8 million in depreciation on generating assets over the term of the order. The additional depreciation will be accumulated in a regulatory liability account to be available to mitigate any potential stranded costs. In addition, the Company has discretionary authority to provide up to an additional $0.3 million per year in storm damage accruals and up to an additional $4.0 million in depreciation expense over the four years. Total storm damages accrued under the order were $1.5 million per year in 2001, 2000, and 1999 which included discretionary expense of $0.3 million in each year. No discretionary depreciation was recorded in the last three years. Over the term of the order, the Company is precluded from asking for a rate increase except upon significant changes in economic conditions, new laws, or regulations. There is a quarterly monitoring of the Company's earnings performance. The Company filed a base rate case November 30, 2001 for the first time since 1985. The primary reason for this base rate case is to recover significant new costs related to the 200 megawatt Plant Wansley power purchase agreement beginning June 2002, as well as other operation and maintenance expense changes. The requested increase is 7.6 percent of total rates (base plus fuel). In the filing, the Company announced it would file in early 2002 for a fuel decrease which would offset most, if not all, of the base rate increase. 4. COMMITMENTS Construction Program The Company is engaged in a continuous construction program, currently estimated to total $34.8 million in 2002, $37.6 million in 2003, and $43.3 million in 2004. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental regulations; increasing costs of labor, equipment, and materials; and changes in cost of capital. The Company does not have any traditional baseload generating plants under construction. However, construction related to new and upgrading of existing transmission and distribution facilities and the upgrading of generating plants will continue. Fuel and Purchased Power Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into long-term commitments for the procurement of fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. The Company has fuel commitments of $34 million for 2002, $0.3 million for each of the four years 2003 through 2006, and $6 million for 2007 and beyond. In addition, the system service company acts as agent for the Company and the other operating companies and Southern Power with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes allocated based on usage projections as of II-203 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report December 31, 2001 are as follows: Year Natural Gas ---- ------------- (MMBtu) 2002 4,765,152 2003 4,356,394 2004 3,049,457 2005 2,115,548 2006 1,804,674 2007 and beyond 612,901 --------------------------------------------------------------- Total commitments 16,704,126 =============================================================== The Company has entered into various long-term commitments for the purchase of electricity, substantially all from affiliated companies, including the Plant Wansley purchased power agreement. Estimated total long-term obligations at December 31, 2001 were as follows: Year Commitments ---- -------------- (in thousands) 2002 $ 9,944 2003 13,640 2004 13,656 2005 13,670 2006 13,686 2007 and beyond 41,152 --------------------------------------------------------------- Total commitments $105,748 =============================================================== Operating Leases The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.4 million for 2001, $0.4 million for 2000, and $0.5 million for 1999. At December 31, 2001, estimated future minimum lease payments for noncancelable operating leases were as follows: Rental Commitments --------------- (in thousands) 2002 $429 2003 429 2004 429 2005 429 2006 429 2007 and thereafter 4,894 -------------------------------------------------------------- Total commitments $7,039 ============================================================== 5. INCOME TAXES At December 31, 2001, tax-related regulatory assets and liabilities were $12.3 million and $13.8 million, respectively. 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. Details of income tax provisions are as follows: 2001 2000 1999 --------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $ 27,991 $11,102 $12,968 Deferred (17,951) 75 (3,329) ------------------------------------------------------------------ 10,040 11,177 9,639 ------------------------------------------------------------------ State -- Currently payable 4,282 1,744 2,193 Deferred (2,577) 653 (24) ------------------------------------------------------------------ 1,705 2,397 2,169 ------------------------------------------------------------------ Total $ 11,745 $13,574 $11,808 ================================================================== 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: 2001 2000 --------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $81,654 $76,901 Property basis differences (1,437) 5,904 Other 6,566 17,807 ------------------------------------------------------------------ Total 86,783 100,612 ------------------------------------------------------------------ Deferred tax assets: Pension and other benefits 11,403 9,744 Other 10,560 7,662 ------------------------------------------------------------------ Total 21,963 17,406 ------------------------------------------------------------------ Total deferred tax liabilities, net 64,820 83,206 Portion included in current assets (liabilities), net 12,511 (3,450) ------------------------------------------------------------------ Accumulated deferred income taxes in the Balance Sheets $77,331 $79,756 ================================================================== In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. II-204 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report Credits amortized in this manner amounted to $0.7 million per year in 2001, 2000, and 1999. At December 31, 2001, all investment tax credits available to reduce federal income taxes payable had been utilized. A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2001 2000 1999 ----------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of Federal income tax benefit 3 4 4 Other (3) (2) (5) ---------------------------------------------------------------- Effective income tax rate 35% 37% 34% ================================================================ Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability. 6. CAPITALIZATION Trust Preferred Securities In December 1998, Savannah Electric Capital Trust I, of which the Company owns all of the common securities, issued $40 million of 6.85% mandatorily redeemable preferred securities. Substantially all of the assets of the Trust are $40 million aggregate principal amount of the Company's 6.85% junior subordinated notes due December 31, 2028. The Company considers that the mechanisms and obligations relating to the trust preferred securities, taken together, constitute a full and unconditional guarantee by the Company of payment obligations with respect to the preferred securities of Savannah Electric Capital Trust I. Savannah Electric Capital Trust I is a subsidiary of the Company, and accordingly is consolidated in the Company's financial statements. Long-Term Debt and Capital Leases The Company's Indenture related to its First Mortgage Bonds is unlimited as to the authorized amount of bonds which may be issued, provided that required property additions, earnings, and other provisions of such Indenture are met. Maturities and retirements of long-term debt were $50.7 million in 2001, $0.4 million in 2000, and $16.2 million in 1999. In May 2001, the Company issued $20 million of series B 5.12% senior notes maturing May 15, 2003 and $45 million of series C 6.55% senior notes maturing May 15, 2008. The Company used these proceeds to redeem its $20 million 6 3/8 Series First Mortgage Bonds due July 1, 2003, to repay long-term bank loans in the amount of $30 million, and to repay a portion of its short-term indebtedness. Assets acquired under capital leases are recorded as utility plant in service, and the related obligation is classified as other long-term debt. Leases are capitalized at the net present value of the future lease payments. However, for ratemaking purposes, these obligations are treated as operating leases, and as such, lease payments are charged to expense as incurred. Securities Due Within One Year A summary of the sinking fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows: 2001 2000 --------------------- (in thousands) Bond sinking fund requirement $436 $ 642 Less: Portion to be satisfied by certifying property additions - 642 -------------------------------------------------------- ---------- Cash sinking fund requirement 436 - Other long-term debt maturities 742 30,698 ------------------------------------------------------------------- Total $1,178 $30,698 =================================================================== The first mortgage bond improvement (sinking) fund requirements amount to 1 percent of each outstanding series of bonds authenticated under the Indenture prior to January 1 of each year, other than those issued to collateralize pollution control and other obligations. The requirements may be satisfied by depositing cash or reacquiring bonds, or by pledging additional property equal to 1 2/3 times the requirements. The sinking fund requirements of first mortgage bonds were satisfied by cash redemption in 2001 and by certifying property additions in 2000. It is anticipated that the 2002 requirement will be satisfied by cash redemption. II-205 NOTES (continued) Savannah Electric and Power Company 2001 Annual Report Sinking fund requirements and/or maturities through 2006 applicable to long-term debt are as follows: $1.2 million in 2002; $20.7 million in 2003; $0.6 million in 2004; $0.6 million in 2005; and $20.6 million in 2006. Bank Credit Arrangements At the end of 2001, unused credit arrangements with five banks totaled $65.5 million and expire at various times during 2002 and 2003. The Company has revolving credit arrangements of $20 million, of which $10 million expires April 30, 2003 and $10 million expires December 31, 2003. One of these agreements allows short-term borrowings to be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at the Company's option. In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company operating companies. At December 31, 2001, the Company had outstanding $32.2 million of commercial paper. The Company's committed credit arrangements provide liquidity support to the Company's variable rate obligations and to its commercial paper program. The amount of variable rate obligations outstanding at December 31, 2001 was $22.6 million. Assets Subject to Lien As amended and supplemented, the Company's Indenture of Mortgage, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises. A second lien for $14 million in pollution control obligations is secured by a portion of the Plant McIntosh property. Common Stock Dividend Restrictions The Company's Indenture contains certain limitations on the payment of cash dividends on common stock. At December 31, 2001, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Indenture. 7. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial data for 2001 and 2000 are as follows (in thousands): Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock ------------------------------------------------------------------ March 2001 $61,691 $ 6,799 $ 1,476 June 2001 73,970 14,620 6,246 September 2001 93,583 22,332 11,309 December 2001 54,608 5,791 3,032 March 2000 $52,390 $ 6,583 $ 1,643 June 2000 72,780 14,904 6,287 September 2000 98,849 24,461 12,351 December 2000 71,699 6,477 2,688 --------------------------------------------------------------- The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors. II-206
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 Savannah Electric and Power Company 2001 Annual Report ---------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ---------------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands) $283,852 $295,718 $251,594 $254,455 $226,277 Net Income after Dividends on Preferred Stock (in thousands) $22,063 $22,969 $23,083 $23,644 $23,847 Cash Dividends on Common Stock (in thousands) $21,700 $24,300 $25,200 $23,500 $20,500 Return on Average Common Equity (percent) 12.54 13.13 13.16 13.44 13.71 Total Assets (in thousands) $594,743 $594,227 $570,218 $555,799 $547,352 Gross Property Additions (in thousands) $31,296 $27,290 $29,833 $18,071 $18,846 ---------------------------------------------------------------------------------------------------------------------------------- Capitalization (in thousands): Common stock equity $176,918 $174,994 $174,847 $175,865 $175,631 Preferred stock - - - - 35,000 Company obligated mandatorily redeemable preferred securities 40,000 40,000 40,000 40,000 - Long-term debt 160,709 116,902 147,147 163,443 142,846 ---------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) $377,627 $331,896 $361,994 $379,308 $353,477 ================================================================================================================================== Capitalization Ratios (percent): Common stock equity 46.8 52.7 48.3 46.4 49.7 Preferred stock - - - - 9.9 Company obligated mandatorily redeemable preferred securities 10.6 12.1 11.0 10.5 - Long-term debt 42.6 35.2 40.7 43.1 40.4 ---------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 ================================================================================================================================== Security Ratings: First Mortgage Bonds - Moody's A1 A1 A1 A1 A1 Standard and Poor's A+ A+ AA- AA- AA- Preferred Stock - Moody's Baa1 a2 a2 a2 a2 Standard and Poor's BBB+ BBB+ A- A A Unsecured Long-Term Debt - Moody's A2 - - - - Standard and Poor's A - - - - ================================================================================================================================== Customers (year-end): Residential 117,199 115,646 112,891 110,437 109,092 Commercial 16,121 15,727 15,433 15,328 14,233 Industrial 76 75 67 63 64 Other 474 444 417 377 1,129 ---------------------------------------------------------------------------------------------------------------------------------- Total 133,870 131,892 128,808 126,205 124,518 ================================================================================================================================== Employees (year-end): 550 554 533 542 535 ----------------------------------------------------------------------------------------------------------------------------------
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SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued) Savannah Electric and Power Company 2001 Annual Report ----------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ----------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands): Residential $123,819 $129,520 $112,371 $109,393 $96,587 Commercial 100,835 102,116 88,449 86,231 78,949 Industrial 34,971 40,839 32,233 37,865 35,301 Other 9,547 10,147 9,212 8,838 8,621 ----------------------------------------------------------------------------------------------------------------------------- Total retail 269,172 282,622 242,265 242,327 219,458 Sales for resale - non-affiliates 8,884 4,748 3,395 4,548 3,467 Sales for resale - affiliates 3,205 4,974 4,151 3,016 2,052 ----------------------------------------------------------------------------------------------------------------------------- Total revenues from sales of electricity 281,261 292,344 249,811 249,891 224,977 Other revenues 2,591 3,374 1,783 4,564 1,300 ----------------------------------------------------------------------------------------------------------------------------- Total $283,852 $295,718 $251,594 $254,455 $226,277 ============================================================================================================================= Kilowatt-Hour Sales (in thousands): Residential 1,658,735 1,671,089 1,579,068 1,539,792 1,428,337 Commercial 1,388,357 1,369,448 1,287,832 1,236,337 1,156,078 Industrial 787,674 800,150 713,448 900,012 881,261 Other 133,967 135,824 132,555 131,142 124,490 ----------------------------------------------------------------------------------------------------------------------------- Total retail 3,968,733 3,976,511 3,712,903 3,807,283 3,590,166 Sales for resale - non-affiliates 111,145 77,481 51,548 53,294 94,280 Sales for resale - affiliates 87,799 88,646 76,988 58,415 54,509 ----------------------------------------------------------------------------------------------------------------------------- Total 4,167,677 4,142,638 3,841,439 3,918,992 3,738,955 ============================================================================================================================= Average Revenue Per Kilowatt-Hour (cents): Residential 7.46 7.75 7.12 7.10 6.76 Commercial 7.26 7.46 6.87 6.97 6.83 Industrial 4.44 5.10 4.52 4.21 4.01 Total retail 6.78 7.11 6.52 6.36 6.11 Sales for resale 6.08 5.85 5.87 6.77 3.71 Total sales 6.75 7.06 6.50 6.38 6.02 Residential Average Annual Kilowatt-Hour Use Per Customer 14,241 14,593 14,100 14,061 13,231 Residential Average Annual Revenue Per Customer $1,063.07 $1,131.08 $1,003.39 $998.94 $894.73 Plant Nameplate Capacity Ratings (year-end) (megawatts) 788 788 788 788 788 Maximum Peak-Hour Demand (megawatts): Winter 758 724 719 582 625 Summer 846 878 875 846 802 Annual Load Factor (percent) 55.9 53.4 51.2 54.9 54.3 Plant Availability Fossil-Steam (percent): 81.2 78.5 72.8 72.9 93.7 ----------------------------------------------------------------------------------------------------------------------------- Source of Energy Supply (percent): Coal 50.5 51.6 44.6 41.6 34.4 Oil and gas 4.0 6.9 12.3 12.9 5.2 Purchased power - From non-affiliates 5.3 7.7 5.3 3.4 1.4 From affiliates 40.2 33.8 37.8 42.1 59.0 ----------------------------------------------------------------------------------------------------------------------------- Total 100.0 100.0 100.0 100.0 100.0 =============================================================================================================================
II-208 PART III Items 10, 11, 12 and 13 for SOUTHERN are incorporated by reference to ELECTION OF DIRECTORS in SOUTHERN's definitive Proxy Statement relating to the 2002 Annual Meeting of Stockholders. Additionally, Items 10, 11, 12 and 13 for ALABAMA, GEORGIA, GULF and MISSISSIPPI are incorporated by reference to the Information Statements of ALABAMA, GEORGIA, GULF and MISSISSIPPI relating to each of their respective 2002 Annual Meetings of Shareholders. The ages of directors and executive officers in Item 10 set forth below are as of December 31, 2001. ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Identification of directors of SAVANNAH. Anthony R. James President and Chief Executive Officer Age 51 Served as Director since 5-3-01 Gus H. Bell (1) Age 64 Served as Director since 7-20-99 Archie H. Davis (1) Age 60 Served as Director since 2-18-97 Walter D. Gnann (1) Age 66 Served as Director since 5-17-83 Robert B. Miller, III (1) Age 56 Served as Director since 5-17-83 Arnold M. Tenenbaum (1) Age 65 Served as Director since 5-17-77 (1) No position other than Director. Each of the above is currently a director of SAVANNAH, serving a term running from the last annual meeting of SAVANNAH's stockholder (May 3, 2001) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. James, whose election was effective on the date indicated. There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of SAVANNAH acting solely in their capacities as such. Identification of executive officers of SAVANNAH. Anthony R. James President, Chief Executive Officer and Director Age 51 Served as Executive Officer since 7-27-00 W. Miles Greer Vice President - Customer Operations and External Affairs Age 58 Served as Executive Officer since 11-20-85 Sandra R. Miller Vice President - Power Generation Age 49 Served as Executive Officer since 7-26-01 Kirby R. Willis Vice President, Treasurer and Chief Financial Officer Age 50 Served as Executive Officer since 1-1-94 Each of the above is currently an executive officer of SAVANNAH, serving a term running from the meeting of the directors held on July 26, 2001 for the ensuing year. There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of SAVANNAH acting solely in their capacities as such. Identification of certain significant employees. None. Family relationships. None. III-1 Business experience. Anthony R. James - President and Chief Executive Officer since 2001. He previously served as Vice President of Power Generation and Senior Production Officer from 2000 to 2001 and also as Central Cluster Manager at GEORGIA's Plant Scherer from 2000 to 2001. He served as Plant Manager at GEORGIA's Plant Scherer from 1996 to 2000. Director of SunTrust Bank of Savannah. Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell and DeYoung, Inc., (specializing in environmental, industrial, structural, architectural and civil engineering), Savannah, Georgia. Director of SunTrust Bank of Savannah. Archie H. Davis - President and Chief Executive Officer of The Savannah Bancorp and Chief Executive Officer of The Savannah Bank, N.A., Savannah, Georgia. Member of the Board of Directors of Thomaston Mills, Thomaston, Georgia. Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc., Springfield, Georgia. Robert B. Miller, III - President of American Building Systems, Inc., Savannah, Georgia. Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation. Director of First Union Bank of Georgia, First Union Bank of Savannah and Cerulean Corporation. W. Miles Greer - Vice President of Customer Operations and External Affairs since 1998. He previously served as Vice President of Marketing and Customer Service from 1994 to 1998. Responsible for customer services, transmission and distribution, engineering, system operation and external affairs. Sandra R. Miller - Vice President of Power Generation since 2001. She previously served as Manager of Technical Training at SCS from 1998 to 2001 and Team Leader at GEORGIA's Plant Bowen from June 1996 to June 1998. Responsible for operations and maintenance of Plants Kraft, Riverside and McIntosh. Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since 1994 and Assistant Corporate Secretary since 1998. Responsible primarily for accounting, financial, labor relations, corporate services, corporate compliance, environmental and safety activities. Involvement in certain legal proceedings. None Section 16(a) Beneficial Ownership Reporting Compliance. No late filers. III-2 Item 11. EXECUTIVE COMPENSATION Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the three most highly compensated executive officers of SAVANNAH serving during 2001.
ANNUAL COMPENSATION LONG-TERM COMPENSATION Number of Securities Long- Name Underlying Term and Other Annual Stock Incentive All Other Principal Compensation Options Payouts Compensation Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3 ------------------------------------------------------------------------------------------------------------------------ G. Edison Holland, Jr.4 President, 2001 333,539 324,022 3,692 68,071 - 49,827 Chief Executive 2000 295,812 243,263 24,438 25,667 - 15,453 Officer, Director 1999 254,914 42,626 21,588 8,375 166,052 13,392 Anthony R. James5 President, Chief 2001 210,856 177,858 1,328 31,363 - 30,195 Executive Officer, 2000 175,048 161,442 - 12,752 - 7,582 Director 1999 - - - - - - W. Miles Greer 2001 184,066 104,286 666 32,505 - 8,567 Vice President 2000 177,013 100,923 601 13,416 - 16,982 1999 168,713 21,322 1,874 6,130 79,476 15,150 Kirby R. Willis Vice President, 2001 168,747 100,480 490 29,993 - 8,495 Chief Financial 2000 162,279 97,394 4,908 8,785 - 12,159 Officer, Treasurer 1999 156,068 19,546 259 5,028 79,476 11,767 Sandra R. Miller6 2001 112,802 83,015 8,123 1,896 - 20,749 Vice President 2000 - - - - - - 1999 - - - - - - ----------------------------------- 1 Tax reimbursement by SAVANNAH on certain personal benefits. 2 Payouts made in 2000 for the four-year performance period ending December 31, 1999. 3 SAVANNAH contributions in 2001 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP), Supplemental Benefit Plan (SBP) or Above-Market Earnings on deferred compensation (AME) and tax sharing benefits paid to participants who elected receipt of dividends on SOUTHERN's common stock held in the ESP are as follows: Name ESP ESOP SBP or AME ESP Tax Sharing Benefits ---- --- ---- ---------- ------------------------ G. Edison Holland, Jr. $6,853 $764 $9,861 $721 Anthony R. James 6,853 764 3,181 - W. Miles Greer 7,650 764 153 - Kirby R. Willis 5,923 764 1,808 - Sandra R. Miller 5,051 698 - - In 2001, this amount for Mr. Holland, Mr. James and Ms. Miller includes $31,628, $19,397 and $15,000, respectively, of additional incentive compensation. 4 Mr. Holland transferred to SOUTHERN on May 1, 2001. 5 Mr. James became President and Chief Executive Officer effective May 1, 2001. 6 Ms. Miller became an executive officer of SAVANNAH on July 26, 2001.
III-3 STOCK OPTION GRANTS IN 2001 Stock Option Grants. The following table sets forth all stock option grants to the named executive officers of SAVANNAH during the year ending December 31, 2001.
Individual Grants Grant Date Value # of % of Total Securities Options Exercise Underlying Granted to or Options Employees in Base Price Expiration Grant Date Name Granted7 Fiscal Year8 ($/Sh)7 Date7 Present Value($)9 ----------------------------------------------------------------------------------------------------------------- SAVANNAH G. Edison Holland, Jr. 33,159 17 19.0762 2/16/2011 146,894 34,912 17 22.4250 4/16/2011 166,530 Anthony R. James 17,794 9 19.0762 2/16/2011 78,827 13,569 7 22.4250 4/16/2011 64,724 W. Miles Greer 17,007 8 19.0762 2/16/2011 75,341 15,498 8 22.4250 4/16/2011 73,925 Kirby R. Willis 15,591 8 19.0762 2/16/2011 69,068 14,402 7 22.4250 4/16/2001 68,698 Sandra R. Miller 1,337 1 19.0762 2/16/2011 5,923 559 0 22.4250 4/16/2011 2,666 -------------------------------
7 Under the terms of the Omnibus Incentive Compensation Plan, stock option grants were made on February 16, 2001 and April 16, 2001, and vest annually at a rate of one-third on the anniversary date of the grant. Grants fully vest upon termination as a result of death, total disability or retirement and expire five years after retirement, three years after death or total disability or their normal expiration date if earlier. The exercise price is the average of the high and low price of SOUTHERN's common stock on the date granted. Options may be transferred to certain family members, family trusts and family limited partnerships. The number of options granted on February 16, 2001 and the exercise price thereof were adjusted after the spin-off of Mirant under the antidilution provisions of the plan such that the options had the same aggregate intrinsic value on the day of the spin-off as the day before. 8 A total of 200,946 stock options were granted in 2001. 9 Value was calculated using the Black-Scholes option valuation model. The actual value, if any, ultimately realized depends on the market value of SOUTHERN's common stock at a future date. Significant assumptions are shown below:
Risk-free Dividend Discount for forfeiture risk: Grant Volatility rate of return opportunity Term before after Date vesting vesting ------------------------------------------------------------------------------------------------------------------- 2/16/01 25.63% 4.83% 50% 10 7.79% 12.45% 4/16/01 26.50% 4.65% 50% 10 7.79% 11.77% ------------------------------------------------------------------------------------------------------------------- These assumptions reflect the effects of cash dividend equivalents paid to participants under SOUTHERN's Performance Dividend Plan assuming targets are met.
III-4 AGGREGATED STOCK OPTION EXERCISES IN 2001 AND YEAR-END OPTION VALUES Aggregated Stock Option Exercises. The following table sets forth information concerning options exercised during the year ending December 31, 2001 by the named executive officers and the value of unexercised options held by them as of December 31, 2001.
Number of Securities Value of Underlying Unexercised Unexercised In-the-Money Options at Options at Fiscal Fiscal Year-End (#) Year-End($)10 Shares Acquired Value Exercisable/ Exercisable/ Name on Exercise (#) Realized($)11 Unexercisable Unexercisable -------------------------------------------------------------------------------------------------------------- SAVANNAH G. Edison Holland, Jr. 38,297 419,217 35,004/99,611 325,235/637,703 Anthony R. James 6,757 67,947 17,972/47,384 166,611/317,077 W. Miles Greer - - 29,132/49,916 288,866/331,185 Kirby R. Willis 6,218 55,902 25,096/41,929 248,549/261,847 Sandra R. Miller - - 560/3,015 5,980/21,972 ---------------------------- 10 This column represents the excess of the fair market value of SOUTHERN's common stock of $25.35 per share, as of December 31, 2001, above the exercise price of the options. The Exercisable column reports the "value" of options that are vested and therefore could be exercised. The Unexercisable column reports the "value" of options that are not vested and therefore could not be exercised as of December 31, 2001. 11 The "Value Realized" is ordinary income, before taxes, and represents the amount equal to the excess of the fair market value of the shares at the time of exercise above the exercise price.
III-5 DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE Pension Plan Table. The following table sets forth the estimated annual pension benefits payable at normal retirement age under SOUTHERN's qualified Pension Plan, as well as non-qualified supplemental benefits, based on the stated compensation and years of service with the SOUTHERN system for Ms. Miller and Messrs. Holland and James. Compensation for pension purposes is limited to the average of the highest three of the final 10 years' compensation. Compensation is base salary plus the excess of annual incentive compensation over 15 percent of base salary. These compensation components are reported under columns titled "Salary" and "Bonus" in the Summary Compensation Table on page III-3.
Years of Accredited Service Remuneration 15 20 25 30 35 40 ------------ ----------------------------------------------------------------- $ 100,000 $ 25,500 $ 34,000 $ 42,500 $ 51,000 $ 59,500 $ 68,000 300,000 76,500 102,000 127,500 153,000 178,500 204,000 500,000 127,500 170,000 212,500 255,000 297,500 340,000 700,000 178,500 238,000 297,500 357,000 416,500 476,000 900,000 229,500 306,000 382,500 459,000 535,500 612,000 1,100,000 280,500 374,000 467,500 561,000 654,500 748,000 1,300,000 331,500 442,000 552,500 663,000 773,500 884,000
As of December 31, 2001, the applicable compensation levels and years of accredited service for SAVANNAH's named executive officers are presented in the following table: Compensation Accredited Name Level Years of Service G. Edison Holland, Jr.12 $522,288 18 Anthony R. James 299,112 22 W. Miles Greer13 250,600 25 Kirby R. Willis 235,192 27 Sandra R. Miller 156,036 21 The amounts shown in the table were calculated according to the final average pay formula and are based on a single life annuity without reduction for joint and survivor annuities or computation of Social Security offset that would apply in most cases. ----------------------- 12 The number of accredited years of service includes 9 years and 3 months credited to Mr. Holland pursuant to a supplemental pension agreement. 13 The number of accredited years of service includes 7 years and 6 months credited to Mr. Greer pursuant to a supplemental pension agreement. III-6 Effective January 1, 1998, SAVANNAH merged its pension plan into the SOUTHERN Pension Plan. SAVANNAH also has in effect a supplemental executive retirement plan for certain of its executive employees. The plan is designed to provide participants with a supplemental retirement benefit, which, in conjunction with Social Security and benefits under SOUTHERN's qualified pension plan, will equal 70 percent of the highest three of the final 10 years' average annual earnings (excluding incentive compensation). The following table sets forth the estimated combined annual pension benefits under SOUTHERN's pension and SAVANNAH's supplemental executive retirement plans in effect during 2001 which are payable to Messrs. Greer and Willis, upon retirement at the normal retirement age after designated periods of accredited service and at a specified compensation level. Years of Accredited Service Remuneration 15 25 35 -------------------------- -- -- -- $150,000 105,000 105,000 105,000 180,000 126,000 126,000 126,000 210,000 147,000 147,000 147,000 260,000 182,000 182,000 182,000 280,000 196,000 196,000 196,000 300,000 210,000 210,000 210,000 350,000 245,000 245,000 245,000 400,000 280,000 280,000 280,000 430,000 301,000 301,000 301,000 460,000 322,000 322,000 322,000 Compensation of Directors. Standard Arrangements. The following table presents compensation paid to the directors during 2001 for service as a member of the board of directors and any board committee(s), except that employee directors received no fees or compensation for service as a member of the board of directors or any board committee. At the election of the director, all or a portion of the cash retainer may be payable in SOUTHERN's common stock, and all or a portion of the total fees may be deferred under the Deferred Compensation Plan until membership on the board is terminated. Cash Retainer Fee $10,000 Stock Retainer Fee 50 shares in the first quarter 2001 and 85 shares per quarter thereafter Meeting Fees: $750 for each Board or Committee meeting attended Effective January 1, 1997, the Outside Directors Pension Plan (the "Plan") was terminated and benefits payable under the Plan were frozen. Non-employee directors serving as of January 1, 1997 were given a one-time election to receive a Plan benefit buy-out equal to the actuarial present value of future Plan benefits or receive benefits under the terms of the Plan at the annual retainer rate in effect on December 31, 1996. Directors who elected to receive the benefit buy-out were required to defer receipt of that amount under the Deferred Compensation Plan until termination from board membership. Directors who elected to continue to participate under the terms of the Plan are entitled to benefits upon retirement from the board on the retirement date designated in SAVANNAH's by-laws. The annual benefit payable is based upon length of service and varies from 75 percent of the annual retainer in effect on December 31, 1996 if the participant has at least 60 months of service on the board of one or more system companies, to 100 percent if the participant has at least 120 months of such service. Payments will continue for the greater of the lifetime of the participant or 10 years. III-7 Other Arrangements. No director received other compensation for services as a director during the year ending December 31, 2001 in addition to or in lieu of that specified by the standard arrangements specified above. Employment Contracts and Termination of Employment and Change in Control Arrangements. ------------------------------------------------------------------------ SAVANNAH has adopted SOUTHERN's Change in Control Plan, which is applicable to certain of its officers, and has entered into individual change in control agreements with its most highly compensated executive officers. If an executive is involuntarily terminated, other than for cause, within two years following a change in control of SAVANNAH or SOUTHERN, the agreements provide for: o lump sum payment of two or three times annual compensation, o up to five years' coverage under group health and life insurance plans, o immediate vesting of all stock options, stock appreciation rights and restricted stock previously granted, o payment of any accrued long-term and short-term bonuses and dividend equivalents and o payment of any excise tax liability incurred as a result of payments made under any individual agreements. A SOUTHERN change in control is defined under the agreements as: o acquisition of at least 20 percent of the SOUTHERN's stock, o a change in the majority of the members of the SOUTHERN's board of directors, o a merger or other business combination that results in SOUTHERN's shareholders immediately before the merger owning less than 65 percent of the voting power after the merger or o a sale of substantially all the assets of SOUTHERN. A change in control of SAVANNAH is defined under the agreements as: o acquisition of at least 50 percent of SAVANNAH's stock, o a merger or other business combination unless SOUTHERN controls the surviving entity or o a sale of substantially all the assets of SAVANNAH. SOUTHERN also has amended its short- and long-term incentive plans to provide for pro-rata payments at not less than target-level performance if a change in control occurs and the plans are not continued or replaced with comparable plans. Report on Repricing of Options. None. Compensation Committee Interlocks and Insider Participation. None. III-8 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Security Ownership of Certain Beneficial Owners. SOUTHERN is the beneficial owner of 100% of the outstanding common stock of SAVANNAH. ------------------------------------------------------------------------------- Amount and Name and Address Nature of Percent of Beneficial Beneficial of Title of Class Owner Ownership Class ------------------------------------------------------------------------------- Common Stock The Southern Company 100% 270 Peachtree Street, N.W. Atlanta, Georgia 30303 Registrant: SAVANNAH 10,844,635 Security Ownership of Management. The following table shows the number of shares of SOUTHERN common stock owned by the SAVANNAH's directors, nominees and executive officers as of December 31, 2001. It is based on information furnished by the directors, nominees and executive officers. The shares owned by all directors, nominees and executive officers as a group constitute less than one percent of the total number of shares outstanding on December 31, 2001. Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2) ------------------ -------------- -------------------------- Gus H. Bell, III SOUTHERN Common 259 Archie H. Davis SOUTHERN Common 522 Walter D. Gnann SOUTHERN Common 3,433 Anthony R. James SOUTHERN Common 43,854 Robert B. Miller, III SOUTHERN Common 1,128 Arnold M. Tenenbaum SOUTHERN Common 1,167 W. Miles Greer SOUTHERN Common 46,348 Sandra R. Miller SOUTHERN Common 3,365 Kirby R. Willis SOUTHERN Common 40,712 The directors, nominees and executive officers as a group SOUTHERN Common 140,788 (1) As used in this table, "beneficial ownership" means the sole or shared power to vote, or to direct the voting of, a security and/or investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security). (2) The shares shown include shares of SOUTHERN common stock of which certain directors and executive officers have the right to acquire beneficial ownership within 60 days pursuant to the Executive Stock Plan and/or Performance Stock Plan, as follows: Mr. Greer, 41,887 shares; Mr. James, 30,640 shares, Ms. Miller, 1,565 shares and Mr. Willis, 34,933 shares. III-9 Changes in control. SOUTHERN and SAVANNAH know of no arrangements which may at a subsequent date result in any change in control. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Transactions with management and others. Mr. Archie Davis is currently Chief Executive Officer of The Savannah Bank, N.A., Savannah, Georgia and was also President prior to February 2002. During 2001, this bank furnished a number of regular banking services in the ordinary course of business to SAVANNAH. SAVANNAH intends to maintain normal banking relations with the aforesaid bank in the future. Certain business relationships. None. Indebtedness of management. None. Transactions with promoters. None. III-10 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this report on this Form 10-K: (1) Financial Statements: Reports of Independent Public Accountants on the financial statements for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed under Item 8 herein. The financial statements filed as a part of this report for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed under Item 8 herein. (2) Financial Statement Schedules: Reports of Independent Public Accountants as to Schedules for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are included herein on pages IV-12 through IV-17. Financial Statement Schedules for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed in the Index to the Financial Statement Schedules at page S-1. (3) Exhibits: Exhibits for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed in the Exhibit Index at page E-1. (b) Reports on Form 8-K during the fourth quarter of 2001 were as follows: SOUTHERN filed a Current Report on Form 8-K: Date of event: December 20, 2001 Items reported: Item 5 GEORGIA filed a Current Report on Form 8-K: Date of event: December 20, 2001 Items reported: Item 5 GULF filed Current Reports on Form 8-K: Date of event: October 5, 2001 Items reported: Items 5 and 7 Date of event: November 8, 2001 Items reported: Items 5 and 7 IV-1 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. THE SOUTHERN COMPANY By: H. Allen Franklin, Chairman, President and Chief Executive Officer /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. H. Allen Franklin Chairman, President and Chief Executive Officer (Principal Executive Officer) Gale E. Klappa Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) W. Dean Hudson Comptroller and Chief Accounting Officer (Principal Accounting Officer) Directors: Daniel P. Amos L. G. Hardman III Dorrit J. Bern Donald M. James Thomas F. Chapman Zack T. Pate Bruce S. Gordon Gerald J. St. Pe' /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. ALABAMA POWER COMPANY By: Charles D. McCrary, President and Chief Executive Officer /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Charles D. McCrary President, Chief Executive Officer and Director (Principal Executive Officer) William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) Art P. Beattie Vice President and Comptroller (Principal Accounting Officer) Directors: Whit Armstrong Mayer Mitchell David J. Cooper William V. Muse H. Allen Franklin Robert D. Powers R. Kent Henslee C. Dowd Ritter Patricia M. King James H. Sanford James K. Lowder John Cox Webb, IV Wallace D. Malone, Jr. James W. Wright Thomas C. Meredith /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 IV-2 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. GEORGIA POWER COMPANY By: David M. Ratcliffe, President and Chief Executive Officer By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. David M. Ratcliffe President, Chief Executive Officer and Director (Principal Executive Officer) Thomas A. Fanning Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) Cliff S. Thrasher Vice President, Comptroller and Chief Accounting Officer (Principal Accounting Officer) Directors: Juanita P. Baranco James R. Lientz, Jr. Anna R. Cablik Richard W. Ussery William A. Fickling, Jr. William Jerry Vereen H. Allen Franklin Carl Ware L. G. Hardman III E. Jenner Wood, III /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. GULF POWER COMPANY By: Travis J. Bowden, President and Chief Executive Officer /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Travis J. Bowden President, Chief Executive Officer and Director (Principal Executive Officer) Ronnie R. Labrato Vice President, Chief Financial Officer and Comptroller (Principal Financial and Accounting Officer) Directors: C. LeDon Anchors W. Deck Hull, Jr. Fred C. Donovan, Sr. William A. Pullum H. Allen Franklin Joseph K. Tannehill By: /s/ Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 IV-3 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. MISSISSIPPI POWER COMPANY By: Michael D. Garrett, President and Chief Executive Officer /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Michael D. Garrett President, Chief Executive Officer and Director (Principal Executive Officer) Michael W. Southern Vice President, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer) Directors: Tommy E. Dulaney George A. Schloegel Aubrey K. Lucas Gene Warr Malcolm Portera /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. SAVANNAH ELECTRIC AND POWER COMPANY By: Anthony R. James, President and Chief Executive Officer /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Anthony R. James President, Chief Executive Officer and Director (Principal Executive Officer) Kirby R. Willis Vice President, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer) Directors: Gus H. Bell, III Robert B. Miller, III Archie H. Davis Arnold M. Tenenbaum Walter D. Gnann /s/Wayne Boston By: Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 22, 2002 IV-4 Exhibit 21. Subsidiaries of the Registrants.* Jurisdiction of Name of Company Organization ------------------------------------------------------------------------------- The Southern Company Delaware Southern Company Capital Trust I Delaware Southern Company Capital Trust II Delaware Southern Company Capital Trust III Delaware Southern Company Capital Trust IV Delaware Southern Company Capital Trust V Delaware Southern Company Capital Trust VI Delaware Southern Company Capital Trust VII Delaware Southern Company Capital Trust VIII Delaware Southern Company Capital Trust IX Delaware Alabama Power Company Alabama Alabama Power Capital Trust I Delaware Alabama Power Capital Trust II Delaware Alabama Power Capital Trust III Delaware Alabama Power Capital Trust IV Delaware Alabama Power Capital Trust V Delaware Alabama Property Company Alabama Southern Electric Generating Company Alabama Georgia Power Company Georgia Georgia Power Capital Trust I Delaware Georgia Power Capital Trust II Delaware Georgia Power Capital Trust III Delaware Georgia Power Capital Trust IV Delaware Georgia Power Capital Trust V Delaware Georgia Power Capital Trust VI Delaware Georgia Power Capital Trust VII Delaware Georgia Power Capital Trust VIII Delaware Piedmont-Forrest Corporation Georgia Southern Electric Generating Company Alabama Gulf Power Company Maine Gulf Power Capital Trust I Delaware Gulf Power Capital Trust II Delaware Gulf Power Capital Trust III Delaware Gulf Power Capital Trust IV Delaware Mississippi Power Company Mississippi Mississippi Power Capital Trust I Delaware Mississippi Power Capital Trust II Delaware Mississippi Power Capital Trust III Delaware Savannah Electric and Power Company Georgia Savannah Electric Capital Trust I Delaware Savannah Electric Capital Trust II Delaware Southern Power Company Delaware ------------------------------------------------------------------------------- *This information is as of December 31, 2001. In addition, this list omits certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K, Item 601. IV-5 Exhibit 23(a) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 13, 2002 on the financial statements of The Southern Company and its subsidiaries and the related financial statement schedule, included in this Form 10-K, into The Southern Company's previously filed Registration Statement File Nos. 2-78617, 33-3546, 33-54415, 33-57951, 33-58371, 33-60427, 333-09077, 333-31808, 333-44127, 333-44261, 333-64871, 333-65178 and 333-73462. /s/Arthur Andersen LLP Atlanta, Georgia March 19, 2002 IV-6 Exhibit 23(b) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 13, 2002 on the financial statements of Alabama Power Company and the related financial statement schedule, included in this Form 10-K, into Alabama Power Company's previously filed Registration Statement File No. 333-72784. /s/Arthur Andersen LLP Birmingham, Alabama March 19, 2002 IV-7 Exhibit 23(c) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 13, 2002 on the financial statements of Georgia Power Company and the related financial statement schedule, included in this Form 10-K, into Georgia Power Company's previously filed Registration Statement File Nos. 333-75193 and 333-57884. /s/Arthur Andersen LLP Atlanta, Georgia March 19, 2002 IV-8 Exhibit 23(d) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 13, 2002 on the financial statements of Gulf Power Company and the related financial statement schedule, included in this Form 10-K, into Gulf Power Company's previously filed Registration Statement File No. 333-59942. /s/Arthur Andersen LLP Atlanta, Georgia March 19, 2002 IV-9 Exhibit 23(e) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 13, 2002 on the financial statements of Mississippi Power Company and the related financial statement schedule, included in this Form 10-K, into Mississippi Power Company's previously filed Registration Statement File No. 333-45069. /s/Arthur Andersen LLP Atlanta, Georgia March 19, 2002 IV-10 Exhibit 23(f) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 13, 2002 on the financial statements of Savannah Electric and Power Company and the related financial statement schedule, included in this Form 10-K, into Savannah Electric and Power Company's previously filed Registration Statement File No. 333-57886. /s/Arthur Andersen LLP Atlanta, Georgia March 19, 2002 IV-11 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE To The Southern Company: We have audited in accordance with auditing standards generally accepted in the United States, the consolidated financial statements of The Southern Company and its subsidiaries included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to The Southern Company and its subsidiaries (page S-2) is the responsibility of The Southern Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 IV-12 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE To Alabama Power Company: We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Alabama Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Alabama Power Company (page S-3) is the responsibility of Alabama Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/Arthur Andersen LLP Birmingham, Alabama February 13, 2002 IV-13 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE To Georgia Power Company: We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Georgia Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Georgia Power Company (page S-4) is the responsibility of Georgia Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 IV-14 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE To Gulf Power Company: We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Gulf Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Gulf Power Company (page S-5) is the responsibility of Gulf Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 IV-15 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE To Mississippi Power Company: We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Mississippi Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Mississippi Power Company (page S-6) is the responsibility of Mississippi Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 IV-16 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE To Savannah Electric and Power Company: We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Savannah Electric and Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Savannah Electric and Power Company (page S-7) is the responsibility of Savannah Electric and Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002 IV-17 INDEX TO FINANCIAL STATEMENT SCHEDULES Schedule II Valuation and Qualifying Accounts and Reserves 2001, 2000 and 1999 The Southern Company and Subsidiary Companies................... S-2 Alabama Power Company........................................... S-3 Georgia Power Company........................................... S-4 Gulf Power Company.............................................. S-5 Mississippi Power Company....................................... S-6 Savannah Electric and Power Company............................. S-7 Schedules I through V not listed above are omitted as not applicable or not required. Columns omitted from schedules filed have been omitted because the information is not applicable or not required. S-1
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (Stated in Thousands of Dollars) Additions ---------------------------------------- Balance at Beginning Charged to Charged to Other Balance at End Description of Period Income Accounts Deductions of Period -------------------------------- ------------------------ -------------- ------------------- ----------------- -------------- Provision for uncollectible accounts 2001..................... $21,799 $44,272 $269 $41,957 (Note) $24,383 2000..................... 21,834 31,329 39 31,403 (Note) 21,799 1999..................... 11,268 35,476 - 24,910 (Note) 21,834 ------------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-2
ALABAMA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (Stated in Thousands of Dollars) Additions --------------------------------------- Balance at Beginning Charged to Charged to Other Balance at End Description of Period Income Accounts Deductions of Period ------------------------------------ ----------------------- --------------- ------------------ ----------------- --------------- Provision for uncollectible accounts 2001.......................... $6,237 $7,419 $- $8,419 (Note) $5,237 2000.......................... 4,117 9,093 - 6,973 (Note) 6,237 1999.......................... 1,855 13,995 - 11,733 (Note) 4,117 ------------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-3
GEORGIA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (Stated in Thousands of Dollars) Additions --------------------------------------- Balance at Beginning Charged to Charged to Other Balance at End Description of Period Income Accounts Deductions of Period ----------------------------------- ----------------------- -------------- ------------------ ----------------- ---------------- Provision for uncollectible accounts 2001.......................... $5,100 $22,913 $- $19,118 (Note) $8,895 2000.......................... 7,000 10,794 - 12,694 (Note) 5,100 1999.......................... 5,500 14,406 - 12,906 (Note) 7,000 ------------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-4
GULF POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (Stated in Thousands of Dollars) Additions -------------------------------------- Balance at Beginning Charged to Charged to Other Balance at End Description of Period Income Accounts Deductions of Period ------------------------------------ ------------------------ --------------- ------------------ ---------------- --------------- Provision for uncollectible accounts 2001.......................... $1,302 $2,282 $- $2,242(Note) $1,342 2000.......................... 1,026 2,702 - 2,426(Note) 1,302 1999.......................... 996 2,230 - 2,200(Note) 1,026 ------------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-5
MISSISSIPPI POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (Stated in Thousands of Dollars) Additions -------------------------------------- Balance at Beginning Charged to Charged to Other Balance at End Description of Period Income Accounts Deductions of Period ------------------------------------ ------------------------- -------------- ------------------ ---------------- --------------- Provision for uncollectible accounts 2001.......................... $571 $2,877 $(165) $2,427 (Note) $856 2000.......................... 697 1,156 14 1,296 (Note) 571 1999.......................... 621 1,964 - 1,888 (Note) 697 ------------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-6
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (Stated in Thousands of Dollars) Additions ------------------------------------- Balance at Beginning Charged to Charged to Other Balance at End Description of Period Income Accounts Deductions of Period -------------------------------------- ---------------------- ------------ ------------------ --------------- ----------------- Provision for uncollectible accounts 2001.......................... $407 $978 $- $885 (Note) $500 2000.......................... 237 999 - 829 (Note) 407 1999.......................... 284 594 - 641 (Note) 237 ------------------- Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.
S-7 EXHIBIT INDEX The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a pound sign are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 14 of Form 10-K. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 601 of Regulation S-K of the SEC, immediately precedes the exhibits being physically filed with this Form 10-K. (3) Articles of Incorporation and By-Laws SOUTHERN (a) 1 - Composite Certificate of Incorporation of SOUTHERN, reflecting all amendments thereto through January 5, 1994. (Designated in Registration No. 33-3546 as Exhibit 4(a), in Certificate of Notification, File No. 70-7341, as Exhibit A and in Certificate of Notification, File No. 70-8181, as Exhibit A.) (a) 2 - By-laws of SOUTHERN as amended effective October 21, 1991, and as presently in effect. (Designated in Form U-1, File No. 70-8181, as Exhibit A-2.) ALABAMA (b) 1 - Charter of ALABAMA and amendments thereto through January 10, 2001. (Designated in Registration Nos. 2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a), in Certificate of Notification, File No. 70-8191, as Exhibit A, in ALABAMA's Form 10-K for the year ended December 31, 1997, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998, File No. 1-3164, as Exhibit 4.4 and in ALABAMA's Form 10-K for the year ended December 31, 2000, File No. 1-3164, as Exhibit 3(b)2.) *(b) 2 - Amendment to Charter of ALABAMA dated November 21, 2001. *(b) 3 - By-laws of ALABAMA as amended effective April 26, 2001, and as presently in effect. GEORGIA (c) 1 - Charter of GEORGIA and amendments thereto through January 16, 2001. (Designated in Registration Nos. 2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2), 33- E-1 14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in GEORGIA's Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992, File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated October 20, 1993, File No. 1-6468, as Exhibit 4(b), in GEORGIA's Form 10-K for the year ended December 31, 1997, File No. 1-6468, as Exhibit 3(c)2 and in GEORGIA's Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2.) (c) 2 - By-laws of GEORGIA as amended effective November 15, 2000, and as presently in effect. (Designated in GEORGIA's Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)3.) GULF (d) 1 - Restated Articles of Incorporation of GULF and amendments thereto through February 9, 2001. (Designated in Registration No. 33-43739 as Exhibit 4(b)-1, in Form 8-K dated January 15, 1992, File No. 0-2429, as Exhibit 1(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(b)-2, in Form 8-K dated September 22, 1993, File No. 0-2429, as Exhibit 4, in Form 8-K dated November 3, 1993, File No. 0-2429, as Exhibit 4, in GULF's Form 10-K for the year ended December 31, 1997, File No. 0-2429, as Exhibit 3(d)2 and in GULF's Form 10-K for the year ended December 31, 2000, File No. 0-2429, as Exhibit 3(d)2.) *(d) 2 - By-laws of GULF as amended effective May 22, 2001, and as presently in effect. MISSISSIPPI (e) 1 - Articles of Incorporation of MISSISSIPPI, articles of merger of Mississippi Power Company (a Maine corporation) into MISSISSIPPI and articles of amendment to the articles of incorporation of MISSISSIPPI through March 8, 2001. (Designated in Registration No. 2-71540 as Exhibit 4(a)-1, in Form U5S for 1987, File No. 30-222-2, as Exhibit B-10, in Registration No. 33-49320 as Exhibit 4(b)-(1), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibits 4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File No. 0-6849, as Exhibit 4(b)-3, in Form 8-K dated August 18, 1993, File No. 0-6849, as Exhibit 4(b)-3, in MISSISSIPPI's Form 10-K for the year ended December 31, 1997, File No. 0-6849, as Exhibit 3(e)2 and in MISSISSIPPI's Form 10-K for the year ended December 31, 2000, File No. 0-6849, as Exhibit 3(e)2.) *(e) 2 - By-laws of MISSISSIPPI as amended effective February 28, 2001, and as presently in effect. E-2 SAVANNAH (f) 1 - Charter of SAVANNAH and amendments thereto through December 2, 1998. (Designated in Registration Nos. 33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2), in Form 8-K dated November 9, 1993, File No. 1-5072, as Exhibit 4(b) and in SAVANNAH's Form 10-K for the year ended December 31, 1998, as Exhibit 3(f)2.) (f) 2 - By-laws of SAVANNAH as amended effective May 17, 2000, and as presently in effect. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 2000, File No. 1-5072, as Exhibit 3(f)2.) (4) Instruments Describing Rights of Security Holders, Including Indentures SOUTHERN (a) 1 - Subordinated Note Indenture dated as of February 1, 1997, among SOUTHERN, Southern Company Capital Funding, Inc. and Bankers Trust Company, as Trustee, and indentures supplemental thereto dated as of February 4, 1997. (Designated in Registration Nos. 333-28349 as Exhibits 4.1 and 4.2 and 333-28355 as Exhibit 4.2.) (a) 2 - Subordinated Note Indenture dated as of June 1, 1997, among SOUTHERN, Southern Company Capital Funding, Inc. and Bankers Trust Company, as Trustee, and indentures supplemental thereto through December 23, 1998. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit (4)(a)2, in Form 8-K dated June 18, 1998, File No. 1-3526, as Exhibit 4.2 and in Form 8-K dated December 18, 1998, File No. 1-3526, as Exhibit 4.4.) (a) 3 - Senior Note Indenture dated as of February 1, 2002, among SOUTHERN, Southern Company Capital Funding, Inc. and The Bank of New York, as Trustee, and indentures supplemental thereto through those dated February 1, 2002. (Designated in Form 8-K dated January 29, 2002, File No. 1-3526, as Exhibits 4.1 and 4.2 and in Form 8-K dated January 30, 2002, File No. 1-3526, as Exhibit 4.2.) (a) 4 - Amended and Restated Trust Agreement of Southern Company Capital Trust I dated as of February 1, 1997. (Designated in Registration No. 333-28349 as Exhibit 4.6) (a) 5 - Amended and Restated Trust Agreement of Southern Company Capital Trust II dated as of February 1, 1997. (Designated in Registration No. 333-28355 as Exhibit 4.6) (a) 6 - Amended and Restated Trust Agreement of Southern Company Capital Trust III dated as of June 1, 1997. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit (4)(a)5.) (a) 7 - Amended and Restated Trust Agreement of Southern Company Capital Trust IV dated as of June 1, 1998. (Designated in Form 8-K dated June 18, 1998, File No. 1-3526, as Exhibit 4.5.) E-3 (a) 8 - Amended and Restated Trust Agreement of Southern Company Capital Trust V dated as of December 1, 1998. (Designated in Form 8-K dated December 18, 1998, File No. 1-3526, as Exhibit 4.7A.) (a) 9 - Capital Securities Guarantee Agreement relating to Southern Company Capital Trust I dated as of February 1, 1997. (Designated in Registration No. 333-28349 as Exhibit 4.10) (a) 10 - Capital Securities Guarantee Agreement relating to Southern Company Capital Trust II dated as of February 1, 1997. (Designated in Registration No. 333-28355 as Exhibit 4.10) (a) 11 - Preferred Securities Guarantee Agreement relating to Southern Company Capital Trust III dated as of June 1, 1997. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit (4)(a)8.) (a) 12 - Preferred Securities Guarantee Agreement relating to Southern Company Capital Trust IV dated as of June 1, 1998. (Designated in Form 8-K dated June 18, 1998, File No. 1-3626, as Exhibit 4.8.) (a) 13 - Preferred Securities Guarantee Agreement relating to Southern Company Capital Trust V dated as of December 1, 1998. (Designated in Form 8-K dated December 18, 1998, File No. 1-3526, as Exhibit 4.11A.) ALABAMA (b) 1 - Indenture dated as of January 1, 1942, between ALABAMA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through December 1, 1994. (Designated in Registration Nos. 2-59843 as Exhibit 2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit 2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2, 2-73727 as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083 as Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in ALABAMA's Form 10-K for the year ended December 31, 1990, File No. 1-3164, as Exhibit 4(c), in Registration Nos. 33-43917 as Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated January 20, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated February 17, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated March 10, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Form 8-K dated June 24, 1993, File No. 1-3164, as Exhibit 4, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(b), in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Certificate of Notification, File No. 70-8069, as Exhibit A and in Form 8-K dated November 30, 1994, File No. 1-3164, as Exhibit 4.) E-4 (b) 2 - Subordinated Note Indenture dated as of January 1, 1996, between ALABAMA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indenture supplemental thereto dated as of January 1, 1996. (Designated in Certificate of Notification, File No. 70-8461, as Exhibits E and F.) (b) 3 - Subordinated Note Indenture dated as of January 1, 1997, between ALABAMA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through February 25, 1999. (Designated in Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2 and in Form 8-K dated February 18, 1999, File No. 3164, as Exhibit 4.2.) (b) 4 - Senior Note Indenture dated as of December 1, 1997, between ALABAMA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through August 29, 2001. (Designated in Form 8-K dated December 4, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in Form 8-K dated February 20, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 17, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 11, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 8, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 16, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 7, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 28, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 12, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 19, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 13, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 21, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 11, 2000, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated August 22, 2001, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b).) (b) 5 - Amended and Restated Trust Agreement of Alabama Power Capital Trust I dated as of January 1, 1996. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit D.) (b) 6 - Amended and Restated Trust Agreement of Alabama Power Capital Trust II dated as of January 1, 1997. (Designated in Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibit 4.5.) (b) 7 - Amended and Restated Trust Agreement of Alabama Power Capital Trust III dated as of February 1, 1999. (Designated in Form 8-K dated February 18, 1999, File No. 1-3164, as Exhibit 4.5.) (b) 8 - Guarantee Agreement relating to Alabama Power Capital Trust I dated as of January 1, 1996. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit G.) (b) 9 - Guarantee Agreement relating to Alabama Power Capital Trust II dated as of January 1, 1997. (Designated in Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibit 4.8.) (b) 10 - Guarantee Agreement relating to Alabama Power Capital Trust III dated as of February 1, 1999. (Designated in Form 8-K dated February 18, 1999, File No. 1-3164, as Exhibit 4.8.) E-5 GEORGIA (c) 1 - Indenture dated as of March 1, 1941, between GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto dated as of March 1, 1941, March 3, 1941 (3 indentures), March 6, 1941 (139 indentures), March 1, 1946 (88 indentures) and December 1, 1947, through October 15, 1995. (Designated in Registration Nos. 2-4663 as Exhibits B-3 and B-3(a), 2-7299 as Exhibit 7(a)-2, 2-61116 as Exhibit 2(a)-3 and 2(a)-4, 2-62488 as Exhibit 2(a)-3, 2-63393 as Exhibit 2(a)-4, 2-63705 as Exhibit 2(a)-3, 2-68973 as Exhibit 2(a)-3, 2-70679 as Exhibit 4(a)-(2), 2-72324 as Exhibit 4(a)-2, 2-73987 as Exhibit 4(a)-(2), 2-77941 as Exhibits 4(a)-(2) and 4(a)-(3), 2-79336 as Exhibit 4(a)-(2), 2-81303 as Exhibit 4(a)-(2), 2-90105 as Exhibit 4(a)-(2), 33-5405 as Exhibit 4(a)-(2), 33-14367 as Exhibits 4(a)-(2) and 4(a)-(3), 33-22504 as Exhibits 4(a)-(2), 4(a)-(3) and 4(a)-(4), 33-32420 as Exhibit 4(a)-(2), 33-35683 as Exhibit 4(a)-(2), in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 4(a)(3), in Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibit 4(a)(5), in Registration No. 33-48895 as Exhibit 4(a)-(2), in Form 8-K dated August 26, 1992, File No. 1-6468, as Exhibit 4(a)-(3), in Form 8-K dated September 9, 1992, File No. 1-6468, as Exhibits 4(a)-(3) and 4(a)-(4), in Form 8-K dated September 23, 1992, File No. 1-6468, as Exhibit 4(a)-(3), in Form 8-A dated October 12, 1992, as Exhibit 2(b), in Form 8-K dated January 27, 1993, File No. 1-6468, as Exhibit 4(a)-(3), in Registration No. 33-49661 as Exhibit 4(a)-(2), in Form 8-K dated July 26, 1993, File No. 1-6468, as Exhibit 4, in Certificate of Notification, File No. 70-7832, as Exhibit M, in Certificate of Notification, File No. 70-7832, as Exhibit C, in Certificate of Notification, File No. 70-7832, as Exhibits K and L, in Certificate of Notification, File No. 70-8443, as Exhibit C, in Certificate of Notification, File No. 70-8443, as Exhibit C, in Certificate of Notification, File No. 70-8443, as Exhibit E, in Certificate of Notification, File No. 70-8443, as Exhibit E, in Certificate of Notification, File No. 70-8443, as Exhibit E, in GEORGIA's Form 10-K for the year ended December 31, 1994, File No. 1-6468, as Exhibits 4(c)2 and 4(c)3, in Certificate of Notification, File No. 70-8443, as Exhibit C, in Certificate of Notification, File No. 70-8443, as Exhibit C, in Form 8-K dated May 17, 1995, File No. 1-6468, as Exhibit 4 and in GEORGIA's Form 10-K for the year ended December 31, 1995, File No. 1-6468, as Exhibits 4(c)2, 4(c)3, 4(c)4, 4(c)5 and 4(c)6.) *(c) 2 - Satisfaction and Discharge of Indenture, Release and Deed of Reconveyance dated as of February 27, 2002, by JPMorgan Chase Bank, as Trustee, to GEORGIA relating to the defeasance of the Indenture dated as of March 1, 1941 between GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through October 15, 1995. (c) 3 - Subordinated Note Indenture dated as of August 1, 1996, between GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through January 1, 1997. (Designated in Form 8-K dated August 21, 1996, File No. 1-6468, as Exhibits 4.1 and 4.2 and in Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit 4.2.) E-6 (c) 4 - Subordinated Note Indenture dated as of June 1, 1997, between GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through February 25, 1999. (Designated in Certificate of Notification, File No. 70-8461, as Exhibits D and E and Form 8-K dated February 17, 1999, File No. 1-6468, as Exhibit 4.4.) (c) 5 - Senior Note Indenture dated as of January 1, 1998, between GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through May 8, 2001. (Designated in Form 8-K dated January 21, 1998, File No. 1-6468, as Exhibits 4.1 and 4.2, in Forms 8-K each dated November 19, 1998, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 3, 1999, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated February 15, 2000, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated January 26, 2001, File No. 1-6469 as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated February 16, 2001, File No. 1-6469 as Exhibit 4.2 and in Form 8-K dated May 1, 2001, File No. 1-6468, as Exhibit 4.2.) (c) 6 - Amended and Restated Trust Agreement of Georgia Power Capital Trust I dated as of August 1, 1996. (Designated in Form 8-K dated August 21, 1996, File No. 1-6468, as Exhibit 4.5.) (c) 7 - Amended and Restated Trust Agreement of Georgia Power Capital Trust II dated as of January 1, 1997. (Designated in Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit 4.5.) (c) 8 - Amended and Restated Trust Agreement of Georgia Power Capital Trust III dated as of June 1, 1997. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit C.) (c) 9 - Amended and Restated Trust Agreement of Georgia Power Capital Trust IV dated as of February 1, 1999. (Designated in Form 8-K dated February 17, 1999, as Exhibit 4.7-A) (c) 10 - Guarantee Agreement relating to Georgia Power Capital Trust I dated as of August 1, 1996. (Designated in Form 8-K dated August 21, 1996, File No. 1-6468, as Exhibit 4.8.) (c) 11 - Guarantee Agreement relating to Georgia Power Capital Trust II dated as of January 1, 1997. (Designated in Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit 4.8.) (c) 12 - Guarantee Agreement relating to Georgia Power Capital Trust III dated as of June 1, 1997. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit F.) (c) 13 - Guarantee Agreement relating to Georgia Power Capital Trust IV dated as of February 1, 1999. (Designated in Form 8-K dated February 17, 1999, as Exhibit 4.11-A.) E-7 GULF (d) 1 - Indenture dated as of September 1, 1941, between GULF and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through November 1, 1996. (Designated in Registration Nos. 2-4833 as Exhibit B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as Exhibit 2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2, 33-43739 as Exhibit 4(a)-2, in GULF's Form 10-K for the year ended December 31, 1991, File No. 0-2429, as Exhibit 4(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(a)-3, in Registration No. 33-50165 as Exhibit 4(a)-2, in Form 8-K dated July 12, 1993, File No. 0-2429, as Exhibit 4, in Certificate of Notification, File No. 70-8229, as Exhibit A, in Certificate of Notification, File No. 70-8229, as Exhibits E and F, in Form 8-K dated January 17, 1996, File No. 0-2429, as Exhibit 4, in Certificate of Notification, File No. 70-8229, as Exhibit A, in Certificate of Notification, File No. 70-8229, as Exhibit A and in Form 8-K dated November 6, 1996, File No. 0-2429, as Exhibit 4.) (d) 2 - Subordinated Note Indenture dated as of January 1, 1997, between GULF and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through November 16, 2001. (Designated in Form 8-K dated January 27, 1997, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated July 28, 1997, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.2 and in Form 8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.2.) (d) 3 - Senior Note Indenture dated as of January 1, 1998, between GULF and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through January 30, 2002. (Designated in Form 8-K dated June 17, 1998, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated August 17, 1999, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July 31, 2001, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated October 5, 2001, File No. 0-2429, as Exhibit 4.2 and in Form 8-K dated January 18, 2002, File No. 0-2429, as Exhibit 4.2.) (d) 4 - Amended and Restated Trust Agreement of Gulf Power Capital Trust I dated as of January 1, 1997. (Designated in Form 8-K dated January 27, 1997, File No. 0-2429, as Exhibit 4.5.) (d) 5 - Amended and Restated Trust Agreement of Gulf Power Capital Trust II dated as of January 1, 1998. (Designated in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.5.) (d) 6 - Amended and Restated Trust Agreement of Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.5.) (d) 7 - Guarantee Agreement relating to Gulf Power Capital Trust I dated as of January 1, 1997. (Designated in Form 8-K dated January 27, 1997, File No. 0-2429, as Exhibit 4.8.) E-8 (d) 8 - Guarantee Agreement relating to Gulf Power Capital Trust II dated as of January 1, 1998. (Designated in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.8.) (d) 9 - Guarantee Agreement relating to Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 1998, File No. 0-2429, as Exhibit 4.8.) MISSISSIPPI (e) 1 - Indenture dated as of September 1, 1941, between MISSISSIPPI and Bankers Trust Company, as Successor Trustee, and indentures supplemental thereto through December 1, 1995. (Designated in Registration Nos. 2-4834 as Exhibit B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2, 2-71537 as Exhibit 4(a)-(2), 33-5414 as Exhibit 4(a)-(2), 33-39833 as Exhibit 4(a)-2, in MISSISSIPPI's Form 10-K for the year ended December 31, 1991, File No. 0-6849, as Exhibit 4(b), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibit 4(a)-2, in Second Certificate of Notification, File No. 70-7941, as Exhibit I, in MISSISSIPPI's Form 8-K dated February 26, 1993, File No. 0-6849, as Exhibit 4(a)-2, in Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated June 22, 1993, File No. 0-6849, as Exhibit 1, in Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated March 8, 1994, File No. 0-6849, as Exhibit 4, in Certificate of Notification, File No. 70-8127, as Exhibit C and in Form 8-K dated December 5, 1995, File No. 0-6849, as Exhibit 4.) (e) 2 - Senior Note Indenture dated as of May 1, 1998 between MISSISSIPPI and Bankers Trust Company, as Trustee and indentures supplemental thereto through March 28, 2000. (Designated in Form 8-K dated May 14, 1998, File No. 0-6849, as Exhibits 4.1, 4.2(a) and 4.2(b) and in Form 8-K dated March 22, 2000, File No. 0-6849, as Exhibit 4.2.) (e) 3 - Subordinated Note Indenture dated as of February 1, 1997, between MISSISSIPPI and Bankers Trust Company, as Trustee, and indenture supplemental thereto dated as of February 1, 1997. (Designated in Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibits 4.1 and 4.2.) (e) 4 - Amended and Restated Trust Agreement of Mississippi Power Capital Trust I dated as of February 1, 1997. (Designated in Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibit 4.5.) (e) 5 - Guarantee Agreement relating to Mississippi Power Capital Trust I dated as of February 1, 1997. (Designated in Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibit 4.8.) SAVANNAH (f) 1 - Indenture dated as of March 1, 1945, between SAVANNAH and The Bank of New York, as Trustee, and indentures supplemental thereto through May 1, 1996. (Designated in Registration Nos. 33-25183 as Exhibit 4(a)-(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit 4(a)-(2), in SAVANNAH's Form 10-K for E-9 the year ended December 31, 1991, File No. 1-5072, as Exhibit 4(b), in Form 8-K dated July 8, 1992, File No. 1-5072, as Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit 4(a)-(2), in Form 8-K dated July 22, 1993, File No. 1-5072, as Exhibit 4, in Form 8-K dated May 18, 1995, File No. 1-5072, as Exhibit 4 and in Form 8-K dated May 23, 1996, File No. 1-5072, as Exhibit 4.) (f) 2 - Senior Note Indenture dated as of March 1, 1998 between SAVANNAH and The Bank of New York, as Trustee and indentures supplemental thereto through May 17, 2001. (Designated in Form 8-K dated March 9, 1998, File No. 1-5072, as Exhibits 4.1 and 4.2 and in Form 8-K dated May 8, 2001, File No. 1-5072, as Exhibits 4.2(a) and 4.2(b).) (f) 3 - Subordinated Note Indenture dated as of December 1, 1998, between SAVANNAH and The Bank of New York, as Trustee, and indenture supplemental thereto dated as of December 9, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.3 and 4.4.) (f) 4 - Amended and Restated Trust Agreement of Savannah Electric Capital Trust I dated as of December 1, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.7.) (f) 5 - Guarantee Agreement relating to Savannah Electric Capital Trust I dated as of December 1, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.11.) (10) Material Contracts SOUTHERN (a) 1 - Service contracts dated as of January 1, 1984, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN and Amendment No. 1 dated as of September 6, 1985 between SCS and SOUTHERN. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1984, File No. 1-3526, as Exhibit 10(a) and in SOUTHERN's Form 10-K for the year ended December 31, 1985, File No. 1-3526, as Exhibit 10(a)(3).) *(a) 2 - Service contract dated as of January 1, 2001, between SCS and Southern Power. (a) 3 - Service contract dated as of March 3, 1988, between SCS and SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.) (a) 4 - Service contract dated as of January 15, 1991, between SCS and Southern Nuclear. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1991, File No. 1-3526, as Exhibit 10(a)(4).) (a) 5 - Service contract dated as of December 12, 1994, between SCS and Mobile Energy Services Company, Inc. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)58.) E-10 (a) 6 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)6.) (a) 7 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, ALABAMA and GEORGIA. (Designated in Registration No. 2-59634 as Exhibit 5(c), in GEORGIA's Form 10-K for the year ended December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2) and in ALABAMA's Form 10-K for the year ended December 31, 1994, File No. 1-3164, as Exhibit 10(b)18.) (a) 8 - Joint Committee Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. (Designated in Registration No. 2-61116 as Exhibit 5(d).) (a) 9 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of January 6, 1975, between GEORGIA and OPC. (Designated in Form 8-K for January, 1975, File No. 1-6468, as Exhibit (b)(1).) (a) 10 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between GEORGIA and OPC. (Designated in Form 8-K for January, 1975, File No. 1-6468, as Exhibit (b)(3).) (a) 11 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between GEORGIA and OPC. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(g).) (a) 12 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of March 26, 1976, between GEORGIA and OPC. (Designated in Certificate of Notification, File No. 70-5592, as Exhibit A.) (a) 13 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between GEORGIA and OPC. (Designated in Certificate of Notification, File No. 70-5592, as Exhibit B.) (a) 14 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(1).) (a) 15 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. (Designated in Form 8-K for February 1977, File No. 1-6468, as Exhibit (b)(2).) (a) 16 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-5792, as Exhibit B-1 and in Form 8-K for January 1977, File No. 1-6468, as Exhibit (B)(3).) E-11 (a) 17 - Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-5792, as Exhibit B-2.) (a) 18 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption Agreement dated as of November 16, 1983, between GEORGIA and MEAG. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1983, File No. 1-6468, as Exhibit 10(k)(4).) (a) 19 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(2).) (a) 20 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(4).) (a) 21 - Nuclear Operating Agreement between Southern Nuclear and GEORGIA dated as of July 1, 1993. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 10(a)21.) (a) 22 - Pseudo Scheduling and Services Agreement between GEORGIA and MEAG dated as of April 8, 1997. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 10(a)22.) (a) 23 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of April 19, 1977, between GEORGIA and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(3).) (a) 24 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between GEORGIA and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(7).) (a) 25 - Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 30, 1985, Amendment No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of August 1, 1988 and Amendment No. 4 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-3, in SOUTHERN's Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(2), in SOUTHERN's Form 10-K for the year ended December 31, 1989, File No. 1-3526, as Exhibit 10(n)(2) and in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)54.) (a) 26 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 3, 1985 and Amendment No. 2 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-4, in SOUTHERN's Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(4) and in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)55.) E-12 (a) 27 - Plant Robert W. Scherer Purchase, Sale and Option Agreement dated as of May 15, 1980, between GEORGIA and MEAG. (Designated in Form U-1, File No. 70-6481, as Exhibit B-1.) (a) 28 - Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between GEORGIA and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-2.) (a) 29 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between GEORGIA and GULF. (Designated in Form U-1, File No. 70-6573, as Exhibit B-4, in SOUTHERN's Form 10-K for the year ended December 31, 1987, as Exhibit 10(o)(2) and in SOUTHERN's Form 10-K for the year ended December 31, 1989, as Exhibit 10(n)(2).) (a) 30 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA and GULF. (Designated in Form U-1, File No. 70-6573, as Exhibit B-5.) (a) 31 - Plant Robert W. Scherer Unit No. Four Amended and Restated Purchase and Ownership Participation Agreement by and among GEORGIA, FP&L and JEA, dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. (Designated in Form U-1, File No. 70-7843, as Exhibit B-1 and in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)60.) (a) 32 - Plant Robert W. Scherer Unit No. Four Operating Agreement by and among GEORGIA, FP&L and JEA, dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. (Designated in Form U-1, File No. 70-7843, as Exhibit B-2 and in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)61.) (a) 33 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(d).) (a) 34 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(e).) (a) 35 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(f).) (a) 36 - Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18, 1988, between OPC and GEORGIA. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1988, File No. 1-6468, as Exhibit 10(x).) E-13 (a) 37 - Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between OPC and GEORGIA. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1988, File No. 1-6468, as Exhibit 10(y).) (a) 38 - Purchase and Ownership Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-1.) (a) 39 - Operating Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-2.) (a) 40 - Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Gulf States and MISSISSIPPI. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1981, File No. 0-6849, as Exhibit 10(f), in MISSISSIPPI's Form 10-K for the year ended December 31, 1982, File No. 0-6849, as Exhibit 10(f)(2) and in MISSISSIPPI's Form 10-K for the year ended December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).) (a) 41 - Long Term Transaction Service Agreement between GEORGIA and OPC dated as of February 26, 1999. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1999, File No. 1-3526, as Exhibit 10(a)46.) (a) 42 - Revised and Restated Coordination Services Agreement between and among GEORGIA, OPC and Georgia Systems Operations Corporation dated as of September 10, 1997. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 10(a)48.) (a) 43 - Amended and Restated Nuclear Managing Board Agreement for Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and Dalton dated as of July 1, 1993. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)49.) (a) 44 - Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between GEORGIA and OPC dated as of November 12, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(ff).) (a) 45 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and Dalton dated as of December 7, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(gg).) (a) 46 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December 7, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(hh).) E-14 (a) 47 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1992, File No. 1-3526, as Exhibit 10(a)53.) (a) 48 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and JEA. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)56.) (a) 49 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)57.) (a) 50 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)58.) (a) 51 - Operating Agreement for the Joseph M. Farley Nuclear Plant between ALABAMA and Southern Nuclear dated as of December 23, 1991. (Designated in Form U-1, File No. 70-7530, as Exhibit B-7.) *(a) 52 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002. *(a) 53 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002. # (a) 54 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. (Designated in Form S-8, File No. 333-73462, as Exhibit 4(c).) # (a) 55 - The Deferred Compensation Plan for the Directors of The Southern Company, Amended and Restated effective February 19, 2001. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)59.) # (a) 56 - The Southern Company Outside Directors Pension Plan. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)77.) # (a) 57 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)61.) # (a) 58 - The Southern Company Outside Directors Stock Plan and First Amendment thereto. (Designated in Registration No. 33-54415 as Exhibit 4(c) and in SOUTHERN's Form 10-K for the year ended December 31, 1995, File No. 1-3526, as Exhibit 10(a)79.) E-15 # (a) 59 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)63.) (a) 60 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through Amendment Number Six. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1996, File No. 1-3526, as Exhibit 10(a)83, in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 10(a)79, in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)71, in SOUTHERN's Form 10-K for the year ended December 31, 1999, File No. 1-3526, as Exhibit 10(a)72 and in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526 as Exhibit 10(a)66.) *(a) 61 - Amendment Number Seven to The Southern Company Pension Plan. #*(a) 62 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. #*(a) 63 - The Southern Company Performance Sharing Plan, Amended and Restated effective January 1, 2002. #*(a) 64 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000. (a) 65 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)72.) # (a) 66 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)73.) # (a) 67 - Deferred Compensation Agreement between SOUTHERN, Southern Nuclear and William G. Hairston III. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)81.) # (a) 68 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Warren Y. Jobe. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)82.) # (a) 69 - Amended and Restated Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)79.) # (a) 70 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and A. W. Dahlberg. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)80.) E-16 # (a) 71 - Amended and Restated Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)81.) # (a) 72 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Henry Allen Franklin. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)83.) # (a) 73 - Amended and Restated Change in Control Agreement between SOUTHERN, Southern Nuclear and William G. Hairston, III. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)84.) # (a) 74 - Amended and Restated Change in Control Agreement between SOUTHERN, ALABAMA and Elmer B. Harris. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)85.) # (a) 75 - Amended and Restated Change in Control Agreement between SOUTHERN, SAVANNAH and G. Edison Holland, Jr. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)86.) # (a) 76 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and C. Alan Martin. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)87.) # (a) 77 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Charles Douglas McCrary. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)88.) # (a) 78 - Amended and Restated Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)89.) # (a) 79 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Stephen A. Wakefield. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)90.) # (a) 80 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and W. Lawrence Westbrook. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)91.) # (a) 81 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Gale E. Klappa. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)92.) # (a) 82 - Deferred Compensation Agreement between SOUTHERN and William L. Westbrook. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)94.) #*(a) 83 - First Amendment to Deferred Compensation Agreement between SOUTHERN and William L. Westbrook dated September 7, 2001. E-17 # (a) 84 - Deferred Compensation Agreement between SOUTHERN and Alfred W. Dahlberg, III. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)95.) # (a) 85 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)96.) # (a) 86 - Change in Control Agreement between SOUTHERN, SCS and Robert H. Haubein, Jr. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)97.) # (a) 87 - Master Separation and Distribution Agreement dated as of September 1, 2000 between SOUTHERN and Mirant. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)100.) # (a) 88 - Indemnification and Insurance Matters Agreement dated as of September 1, 2000 between SOUTHERN and Mirant. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)101.) # (a) 89 - Tax Indemnification Agreement dated as of September 1, 2000 among SOUTHERN and its affiliated companies and Mirant and its affiliated companies. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)102.) # (a) 90 - Southern Company Deferred Compensation Trust Agreement dated as of January 1, 2001 between Wachovia Bank, N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, Southern Communications, Energy Solutions, Mirant and Southern Nuclear. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)103.) # (a) 91 - Deferred Stock Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)104.) #*(a) 92 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. ALABAMA (b) 1 - Service contracts dated as of January 1, 1984, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN and Amendment No. 1 dated as of September 6, 1985 between SCS and SOUTHERN. See Exhibit 10(a)1 herein. E-18 (b) 2 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS. See Exhibit 10(a)6 herein. (b) 3 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, ALABAMA and GEORGIA. See Exhibit 10(a)7 herein. (b) 4 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)33 herein. (b) 5 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)34 herein. (b) 6 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein. (b) 7 - Firm Power Purchase Contract between ALABAMA and AMEA. (Designated in Certificate of Notification, File No. 70-7212, as Exhibit B.) (b) 8 - 1991 Firm Power Purchase Contract between ALABAMA and AMEA. (Designated in Form U-1, File No. 70-7873, as Exhibit B-1.) (b) 9 - Purchase and Ownership Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. See Exhibit 10(a)38 herein. (b) 10 - Operating Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. See Exhibit 10(a)39 herein. (b) 11 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit 10(a)47 herein. (b) 12 - Operating Agreement for the Joseph M. Farley Nuclear Plant between ALABAMA and Southern Nuclear dated as of December 23, 1991. See Exhibit 10(a)51 herein. *(b) 13 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)52 herein. *(b) 14 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)53 herein. # (b) 15 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)54 herein. # (b) 16 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See Exhibit 10(a)57 herein. E-19 # (b) 17 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)56 herein. # (b) 18 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)59 herein. (b) 19 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through Amendment Number Six. See Exhibit 10(a)60 herein. *(b) 20 - Amendment Number Seven to The Southern Company Pension Plan. See Exhibit 10(a)61 herein. #*(b) 21 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)62 herein. #*(b) 22 - The Southern Company Performance Sharing Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)63 herein. #*(b) 23 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)64 herein. (b) 24 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)65 herein. # (b) 25 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)66 herein. #*(b) 26 - Deferred Compensation Agreement between ALABAMA and Elmer B. Harris. # (b) 27 - Supplemental Pension Agreement between ALABAMA, GULF and Travis J. Bowden. (Designated in ALABAMA's Form 10-K for the year ended December 31, 1998, File No. 1-3164, as Exhibit 10(b)40.) #*(b) 28 - Deferred Compensation Plan for Directors of Alabama Power Company, Amended and Restated effective January 1, 2001. # (b) 29 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit 10(a)85 herein. # (b) 30 - Southern Company Deferred Compensation Trust Agreement dated as of January 1, 2001 between Wachovia Bank, N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, Southern Communications, Energy Solutions, Mirant and Southern Nuclear. See Exhibit 10(a)90 herein. # (b) 31 - Deferred Stock Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(b)91 herein. E-20 #*(b) 32 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of September 1, 2001, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)92 herein. GEORGIA (c) 1 - Service contracts dated as of January 1, 1984, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN and Amendment No. 1 dated as of September 6, 1985, between SCS and SOUTHERN. See Exhibit 10(a)1 herein. (c) 2 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS. See Exhibit 10(a)6 herein. (c) 3 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, ALABAMA and GEORGIA. See Exhibit 10(a)7 herein. (c) 4 - Joint Committee Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)8 herein. (c) 5 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of January 6, 1975, between GEORGIA and OPC. See Exhibit 10(a)9 herein. (c) 6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between GEORGIA and OPC. See Exhibit 10(a)10 herein. (c) 7 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between GEORGIA and OPC. See Exhibit 10(a)11 herein. (c) 8 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of March 26, 1976, between GEORGIA and OPC. See Exhibit 10(a)12 herein. (c) 9 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between GEORGIA and OPC. See Exhibit 10(a)13 herein. (c) 10 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. See Exhibit 10(a)14 herein. (c) 11 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. See Exhibit 10(a)15 herein. (c) 12 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)16 herein. E-21 (c) 13 - Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)17 herein. (c) 14 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption Agreement dated as of November 16, 1983, between GEORGIA and MEAG. See Exhibit 10(a)18 herein. (c) 15 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)19 herein. (c) 16 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)20 herein. (c) 17 - Nuclear Operating Agreement between Southern Nuclear and GEORGIA dated as of July 1, 1993. See Exhibit 10(a)21 herein. (c) 18 - Pseudo Scheduling and Services Agreement between GEORGIA and MEAG dated as of April 8, 1997. See Exhibit 10(a)22 herein. (c) 19 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of April 19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)23 herein. (c) 20 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)24 herein. (c) 21 - Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 30, 1985, Amendment No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of August 1, 1988 and Amendment No. 4 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)25 herein. (c) 22 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 3, 1985 and Amendment No. 2 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)26 herein. (c) 23 - Plant Robert W. Scherer Purchase, Sale and Option Agreement dated as of May 15, 1980, between GEORGIA and MEAG. See Exhibit 10(a)27 herein. (c) 24 - Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between GEORGIA and Dalton. See Exhibit 10(a)28 herein. (c) 25 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between GEORGIA and GULF. See Exhibit 10(a)29 herein. (c) 26 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA and GULF. See Exhibit 10(a)30 herein. E-22 (c) 27 - Plant Robert W. Scherer Unit No. Four Amended and Restated Purchase and Ownership Participation Agreement by and among GEORGIA, FP&L and JEA dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)31 herein. (c) 28 - Plant Robert W. Scherer Unit No. Four Operating Agreement by and among GEORGIA, FP&L and JEA dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)32 herein. (c) 29 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)33 herein. (c) 30 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)34 herein. (c) 31 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein. (c) 32 - Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18, 1988, between OPC and GEORGIA. See Exhibit 10(a)36 herein. (c) 33 - Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between OPC and GEORGIA. See Exhibit 10(a)37 herein. (c) 34 - Long Term Transaction Service Agreement between GEORGIA and OPC dated as of February 26, 1999. See Exhibit 10(a)41 herein. (c) 35 - Revised and Restated Coordination Services Agreement between and among GEORGIA, OPC and Georgia Systems Operations Corporation dated as of September 10, 1997. See Exhibit 10(a)42 herein. (c) 36 - Amended and Restated Nuclear Managing Board Agreement for Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and Dalton dated as of July 1, 1993. See Exhibit 10(a)43 herein. (c) 37 - Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between GEORGIA and OPC dated as of November 12, 1990. See Exhibit 10(a)44 herein. (c) 38 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and Dalton dated as of December 7, 1990. See Exhibit 10(a)45 herein. (c) 39 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December 7, 1990. See Exhibit 10(a)46 herein. E-23 (c) 40 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and JEA. See Exhibit 10(a)48 herein. (c) 41 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)49 herein. (c) 42 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)50 herein. *(c) 43 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)52 herein. *(c) 44 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)53 herein. # (c) 45 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)54 herein. # (c) 46 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See Exhibit 10(a)57 herein. # (c) 47 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)56 herein. # (c) 48 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)59 herein. (c) 49 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through Amendment Number Six. See Exhibit 10(a)60 herein. *(c) 50 - Amendment Number Seven to The Southern Company Pension Plan. See Exhibit 10(a)61 herein. #*(c) 51 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)62 herein. #*(c) 52 - The Southern Company Performance Sharing Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)63 herein. #*(c) 53 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)64 herein. (c) 54 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)65 herein. # (c) 55 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)66 herein. E-24 # (c) 56 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Warren Y. Jobe. See Exhibit 10(a)68 herein. # (c) 57 - Amended and Restated Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe. See Exhibit 10(a)78 herein. # (c) 58 - Supplemental Pension Agreement between GEORGIA and Warren Y. Jobe. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1998, File No. 1-6468, as Exhibit 10(c)77.) #*(c) 59 - Separation Agreement between GEORGIA and Robert H. Haubein, Jr. dated December 21, 2001 and First Amendment thereto effective December 21, 2001. #*(c) 60 - Separation Agreement between GEORGIA and Fred D. Williams dated December 31, 2001. # (c) 61 - Deferred Compensation Plan For Directors of Georgia Power Company, Amended and Restated Effective February 21, 2001. (Designated in GEORGIA's Form 10-K for the year ended December 31, 2000, File No. 1-6468 as Exhibit 10(c)71 # (c) 62 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit 10(a)85 herein. # (c) 63 - Southern Company Deferred Compensation Trust Agreement dated as of January 1, 2001 between Wachovia Bank, N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, Southern Communications, Energy Solutions, Mirant and Southern Nuclear. See Exhibit 10(a)90 herein. # (c) 64 - Deferred Stock Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein. #*(c) 65 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of September 1, 2001, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10 (a)92 herein. GULF (d) 1 - Service contracts dated as of January 1, 1984, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN and Amendment No. 1 dated as of September 6, 1985, between SCS and SOUTHERN. See Exhibit 10(a)1 herein. (d) 2 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS. See Exhibit 10(a)6 herein. E-25 (d) 3 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between GEORGIA and GULF. See Exhibit 10(a)29 herein. (d) 4 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA and GULF. See Exhibit 10(a)30 herein. (d) 5 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and JEA. See Exhibit 10(a)48 herein. (d) 6 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)33 herein. (d) 7 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)34 herein. (d) 8 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein. (d) 9 - Agreement between GULF and AEC, effective August 1, 1985. (Designated in GULF's Form 10-K for the year ended December 31, 1985, File No. 0-2429, as Exhibit 10(g).) *(d) 10 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)52 herein. *(d) 11 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)53 herein. # (d) 12 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)54 herein. # (d) 13 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See Exhibit 10(a)57 herein. # (d) 14 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)56 herein. # (d) 15 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)59 herein. (d) 16 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through Amendment Number Six. See Exhibit 10(a)60 herein. *(d) 17 - Amendment Number Seven to The Southern Company Pension Plan. See Exhibit 10(a)61 herein. E-26 #*(d) 18 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)64 herein. (d) 19 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)65 herein. # (d) 20 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)66 herein. # (d) 21 - Amended and Restated Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden. See Exhibit 10(a)69 herein. #*(d) 22 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)62 herein. #*(d) 23 - The Southern Company Performance Sharing Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)63 herein. # (d) 24 - Supplemental Pension Agreement between SAVANNAH, GULF and G. Edison Holland, Jr. (Designated in GULF's Form 10-K for the year ended December 31, 1998, File No. 0-2429, as Exhibit 10(d)35.) # (d) 25 - Supplemental Pension Agreement between ALABAMA, GULF and Travis J. Bowden. See Exhibit 10(b)27 herein. # (d) 26 - Deferred Compensation Plan For Directors of Gulf Power Company, Amended and Restated Effective January 1, 2000 and First Amendment thereto. (Designated in GULF's Form 10-K for the year ended December 31, 2000, File No. 0-2429 as Exhibit 10(d)33.) # (d) 27 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit 10(a)85 herein. # (d) 28 - Southern Company Deferred Compensation Trust Agreement dated as of January 1, 2001 between Wachovia Bank, N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, Southern Communications, Energy Solutions, Mirant and Southern Nuclear. See Exhibit 10(a)90 herein. # (d) 29 - Deferred Stock Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein. #*(d) 30 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of September 1, 2001, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)92 herein. E-27 MISSISSIPPI (e) 1 - Service contracts dated as of January 1, 1984, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN and Amendment No. 1 dated as of September 6, 1985, between SCS and SOUTHERN. See Exhibit 10(a)1 herein. (e) 2 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS. See Exhibit 10(a)6 herein. (e) 3 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)33 herein. (e) 4 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)34 herein. (e) 5 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein. (e) 6 - Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Gulf States and MISSISSIPPI. See Exhibit 10(a)40 herein. (e) 7 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit 10(a)47 herein. *(e) 8 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)52 herein. *(e) 9 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)53 herein. # (e) 10 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)54 herein. # (e) 11 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See Exhibit 10(a)57 herein. # (e) 12 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)56 herein. # (e) 13 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)59 herein. (e) 14 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through Amendment Number Six. See Exhibit 10(a)60 herein. E-28 *(e) 15 - Amendment Number Seven to The Southern Company Pension Plan. See Exhibit 10(a)61 herein. #*(e) 16 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)64 herein. (e) 17 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)65 herein. # (e) 18 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)66 herein. # (e) 19 - Amended and Restated Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans. See Exhibit 10(a)71 herein. #*(e) 20 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)62 herein. #*(e) 21 - The Southern Company Performance Sharing Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)63 herein. # (e) 22 - Deferred Compensation Plan for Directors of Mississippi Power Company, Amended and Restated Effective January 1, 2000 and Amendment Number One thereto. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1999, File No. 0-6849 as Exhibit 10(e)37 and in MISSISSIPPI'S Form 10-K for the year December 31, 2000, File No. 0-6849 as Exhibit 10(e)30.) # (e) 23 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit 10(a)85 herein. # (e) 24 - Southern Company Deferred Compensation Trust Agreement dated as of January 1, 2001 between Wachovia Bank, N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, Southern Communications, Energy Solutions, Mirant and Southern Nuclear. See Exhibit 10(a)90 herein. # (e) 25 - Deferred Stock Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein. #*(e) 26 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of September 1, 2001, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)92 herein. SAVANNAH (f) 1 - Service contract dated as of March 3, 1988, between SCS and SAVANNAH. See Exhibit 10(a)3 herein. E-29 (f) 2 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS. See Exhibit 10(a)6 herein. (f) 3 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)33 herein. (f) 4 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)34 herein. (f) 5 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein. (f) 6 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)49 herein. (f) 7 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated December 15, 1992. See Exhibit 10(a)50 herein. *(f) 8 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)52 herein. *(f) 9 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)53 herein. # (f) 10 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)54 herein. # (f) 11 - Supplemental Executive Retirement Plan of SAVANNAH, Amended and Restated effective October 26, 2000. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)13.) # (f) 12 - Deferred Compensation Plan for Key Employees of SAVANNAH, Amended and Restated effective October 26, 2000. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)14.) # (f) 13 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)56 herein. # (f) 14 - Deferred Compensation Plan for Directors of SAVANNAH, Amended and Restated effective October 26, 2000. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)18.) # (f) 15 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)59 herein. (f) 16 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through Amendment Number Six. See Exhibit 10(a)60 herein. E-30 *(f) 17 - Amendment Number Seven to The Southern Company Pension Plan. See Exhibit 10(a)61 herein. #*(f) 18 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)64 herein. (f) 19 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)65 herein. # (f) 20 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit 10(a)66 herein. # (f) 21 - Amended and Restated Change in Control Agreement between SOUTHERN, SAVANNAH and G. Edison Holland, Jr. See Exhibit 10(a)75 herein. # (f) 22 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See Exhibit 10(a)57 herein. #*(f) 23 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)62 herein. #*(f) 24 - The Southern Company Performance Sharing Plan, Amended and Restated effective January 1, 2002. See Exhibit 10(a)63 herein. # (f) 25 - Supplemental Pension Agreement between SAVANNAH, GULF and G. Edison Holland, Jr. See Exhibit 10(d)24 herein. # (f) 26 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit 10(a)85 herein. # (f) 27 - Agreement for supplemental pension benefits between SAVANNAH and William Miles Greer. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)34.) # (f) 28 - Agreement crediting additional service between SAVANNAH and William Miles Greer. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)35.) # (f) 29 - Southern Company Deferred Compensation Trust Agreement dated as of January 1, 2001 between Wachovia Bank, N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, Southern Communications, Energy Solutions, Mirant and Southern Nuclear. See Exhibit 10(a)90 herein. # (f) 30 - Deferred Stock Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein. E-31 #*(f) 31 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of September 1, 2001, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)92 herein. (21) Subsidiaries of Registrants SOUTHERN *(a) - Subsidiaries of Registrant is contained herein at page IV-5. ALABAMA *(b) - Subsidiaries of Registrant is contained herein at page IV-5. GEORGIA *(c) - Subsidiaries of Registrant is contained herein at page IV-5. GULF *(d) - Subsidiaries of Registrant is contained herein at page IV-5. MISSISSIPPI *(e) - Subsidiaries of Registrant is contained herein at page IV-5. SAVANNAH *(f) - Subsidiaries of Registrant is contained herein at page IV-5. (23) Consents of Experts and Counsel SOUTHERN *(a) - The consent of Arthur Andersen LLP is contained herein at page IV-6. ALABAMA *(b) - The consent of Arthur Andersen LLP is contained herein at page IV-7. GEORGIA *(c) - The consent of Arthur Andersen LLP is contained herein at page IV-8. GULF *(d) - The consent of Arthur Andersen LLP is contained herein at page IV-9. E-32 MISSISSIPPI *(e) - The consent of Arthur Andersen LLP is contained herein at page IV-10. SAVANNAH *(f) - The consent of Arthur Andersen LLP is contained herein at page IV-11. (24) Powers of Attorney and Resolutions SOUTHERN *(a) - Power of Attorney and resolution. ALABAMA *(b) - Power of Attorney and resolution. GEORGIA *(c) - Power of Attorney and resolution. GULF *(d) - Power of Attorney and resolution. MISSISSIPPI *(e) - Power of Attorney and resolution. SAVANNAH *(f) - Power of Attorney and resolution. E-33