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 integrated Southeast utilities supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively. More particular information relating to each of the integrated Southeast utilities 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, Energy Solutions, Southern Telecom, SPC and other direct and indirect subsidiaries. Southern LINC provides digital wireless communications services to SOUTHERN's integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Nuclear provides services to ALABAMA's and GEORGIA's nuclear plants. Energy Solutions develops new business opportunities related to energy products and services. Southern Telecom provides wholesale fiber optic solutions to telecommunication providers in the Southeastern United States. SPC, formed in January 2001, will be the primary growth engine for SOUTHERN's 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 also 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
Previously, SOUTHERN owned all the outstanding common stock of Mirant. 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's common stockholders within 12 months of the initial stock offering. On October 2, 2000, Mirant completed an initial public offering of 66.7 million shares. On February 19, 2001, SOUTHERN's board of directors approved the spin off of the remaining ownership of 272 million Mirant shares to be completed in a tax free distribution on April 2, 2001. As a result of the spin off, SOUTHERN's financial statements and related information in Item 8 herein reflect Mirant as discontinued operations. I-1
The SOUTHERN System
Integrated Southeast Utilities
The transmission facilities of each of the integrated Southeast utilities 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 integrated Southeast utilities 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 Integrated Southeast Utilities" 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 integrated Southeast utilities 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 integrated Southeast utilities 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 integrated Southeast utilities are represented on the National Electric Reliability Council.
An intra-system interchange agreement provides for coordinating operations of the power producing facilities of the integrated Southeast utilities 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 integrated Southeast utilities to provide the most economical sources of power consistent with good operation. The resulting benefits and savings are apportioned among the integrated Southeast utilities.
On December 20, 1999, the FERC issued its final rule on RTOs ("Order 2000"). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Utilities were required to make a filing with the FERC by October 16, 2000 explaining how they would respond to Order 2000 consistent with this requirement. On October 16, 2000, SOUTHERN filed its RTO proposal. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of SOUTHERN and other participating utilities in the region. Participants would have the option to either maintain their ownership, divest, sell or lease their transmission assets to the proposed RTO. On March 14, 2001, the FERC rejected SOUTHERN's proposal on the grounds that the limitation of the scope of services to new wholesale transmission and the provision of incentives to passive owners were inconsistent with Order 2000. This order requires a status report from SOUTHERN by May 14, 2001, but does not establish a deadline for SOUTHERN to file a revised petition. Reference is made to each registrant's "Management's Discussion and Analysis - Future Earnings Potential" in Item 7 for additional information.
SCS has contracted with SOUTHERN, each integrated Southeast utility, Mirant, various of the other subsidiaries, Southern Nuclear and SEGCO to furnish, at cost and upon request, the following services: general executive and advisory services, power pool operations, general engineering, design engineering, purchasing, accounting, finance and treasury, taxes, insurance and pensions, corporate, rates, budgeting, public relations, employee relations, systems and procedures and other services with respect to business and operations. Energy Solutions and Southern LINC have also secured from the integrated Southeast utilities 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.
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Other Business
Energy Solutions focuses on new and existing programs to enhance customer satisfaction, efficiency and stockholder value. Examples are: Good Cents, an energy efficiency program for electric utility customers; Energy Services, an energy solutions consultant and contractor for industrial and large commercial customers; and 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.
In 1996, Southern LINC began serving SOUTHERN's integrated Southeast utilities 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 2001-2003 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 bankruptcy court that was amended on September 15, 2000. The proposed plan of reorganization was again amended on February 21, 2001. Reference is made to Note 3 to the financial statements of SOUTHERN in Item 8 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."
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 2001 through 2003 by the integrated Southeast utilities, SEGCO, SCS, Southern LINC and other subsidiaries are estimated as follows: (in millions)
------------------------------ -------- --------- ----------
2001 2002 2003
-------- --------- ----------
ALABAMA $ 735 $ 891 $ 625 GEORGIA 1,613 1,349 785 GULF 279 96 76 MISSISSIPPI 62 60 69 SAVANNAH 33 31 32 SEGCO 16 17 16 SCS 29 21 21 Southern LINC 26 39 26 Other 111 60 1
--------------------------- ----------- --------- ---------- SOUTHERN system $2,904 $2,564 $1,651 =========================== =========== ========= ==========
Included in these estimated totals are expenditures for construction of wholesale generation assets that may be transferred to SPC. Assuming such transfers are made, SPC's projected construction program expenditures are approximately $1.2 billion in 2001, $725 million in 2002, and $452 million in 2003.
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*Southern LINC, SCS, and other businesses plan capital additions to general plant in 2001 of $26 million, $29 million, and $111 million, respectively, while SEGCO plans capital additions of $16 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 6,600 megawatts of new generating capacity scheduled to be placed in service by 2003. Approximately 4,400 megawatts of additional new capacity will be dedicated to the wholesale market and owned by SPC.
In 1991, the Georgia legislature passed legislation which requires GEORGIA and SAVANNAH each 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
Item 2. PROPERTIES
Electric Properties - The Integrated Southeast Utilities
The integrated Southeast utilities and SEGCO, at December 31, 2000, operated 34 hydroelectric generating stations, 33 fossil fuel generating stations, three nuclear generating stations and four combined cycle/cogeneration stations. The amounts of capacity owned by 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 Dahlberg Athens, GA 640,000 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 2,535,155 ---------
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-17
--------------------------- -------------------- ----------------- 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 ------- 241,100
Gaston (SEGCO) Wilsonville, AL 19,680 (7) ----------- Total Combustion Turbines 3,795,637 ----------
Cogeneration Washington County Washington County, AL 123,428 GE Plastics Project Burkeville, AL 104,800 Theodore Theodore, AL 236,418 ----------- ALABAMA Total 464,646 -----------
Combined Cycle Barry Mobile, AL ALABAMA Total 535,212 -------
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 40,000 ----------- ALABAMA Total 1,593,600 ----------
--------------------------- -------------------- -----------------
--------------------------- -------------------- ----------------- 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 2,671,336 -----------
Total Generating Capacity 32,806,926 ===========
------------------------------------------------ -----------------
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.
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Except as discussed below under "Titles to Property," the principal plants and other important units of the integrated Southeast utilities 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, 2000, the unamortized portion of this cost was $34.8 million.
The all-time maximum demand on the integrated Southeast utilities 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 integrated Southeast utilities 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:
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.
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Titles to Property
The integrated Southeast utilities' and SEGCO's interests in the principal plants (other than certain pollution control facilities, one small hydroelectric generating station leased by GEORGIA 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 (except for SEGCO) and to excepted encumbrances as defined therein. The integrated Southeast utilities 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.
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Item 3.
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. ALABAMA (United States District Court for the Northern District of Alabama)
Reference is made to Note 3 to ALABAMA's financial statements in Item 8 herein under the caption "Environmental Litigation."
(2) United States of America v. GEORGIA and SAVANNAH (United States District Court for the Northern District of Georgia)
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 and denied the EPA's motion to add GULF and MISSISSIPPI as defendants due to lack of jurisdiction.
Reference is made to Note 3 to GEORGIA's financial statements in Item 8 herein under the caption "Environmental Litigation."
(3) Cooper et al. v. GEORGIA, SOUTHERN, SCS and Energy Solutions (Superior Court of Fulton County, Georgia)
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein under the caption "Race Discrimination Litigation."
(4) GEORGIA has been designated as a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act with respect to a site in Brunswick, Georgia.
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).
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8 herein under the caption "Mobile Energy Services' Petition for Bankruptcy."
(6) Gordon v. SOUTHERN et al. (United States District Court for the Southern District of California)
Reference is made to Note 3 to SOUTHERN"s financial statements in Item 8 herein under the caption "California Electricity Markets Litigation."
(7) Pier 23 Restaurant v. SOUTHERN et al. (United States District Court for the Northern District of California)
Reference is made to Note 3 to SOUTHERN"s financial statements in Item 8 herein under the caption "California Electricity Markets Litigation."
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 integrated Southeast utilities, SCS, Southern Nuclear, 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.
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Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
ALABAMA
ALABAMA held a special meeting of shareholders on December 14, 2000, for the purpose of amending its charter to provide to the holders of Preferred Stock the right to vote at all elections of directors of ALABAMA. The amendment was passed and the vote tabulation was as follows: Shares For Against Abstain
Common Stock 5,608,955 0 0 Preferred Stock 1,505,832 462,101 127,473 --------- ------- ------- Total 7,114,787 462,101 127,473 ========= ======= =======
GEORGIA
By unanimous written consent effective December 14, 2000, GEORGIA's common shareholder authorized amending GEORGIA's charter to provide to the holders of Preferred Stock the right to vote at all elections of directors of GEORGIA. The vote tabulation was as follows: Shares For Against Abstain
Common Stock 7,761,500 0 0
GULF
GULF held a special meeting of shareholders on December 14, 2000, for the purpose of amending its charter to provide to the holders of Preferred Stock the right to vote at all elections of directors of GULF. The amendment was passed and the vote tabulation was as follows: Shares For Against Abstain
Common Stock 992,717 0 0 Preferred Stock 26,842 1,321 21 ----------- ----- -- Total 1,019,559 1,321 21 =========== ===== ==
MISSISSIPPI
MISSISSIPPI held a special meeting of shareholders on December 14, 2000, for the purpose of amending its charter to provide to the holders of Preferred Stock the right to vote at all elections of directors of MISSISSIPPI. The amendment was passed and the vote tabulation was as follows: Shares For Against Abstain
Common Stock 1,121,000 0 0 Preferred Stock 196,119 10,363 11,762 ----------- ------ ------ Total 1,317,119 10,363 11,762 =========== ====== ======
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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, 2000.
A. W. Dahlberg Chairman and Director Age 60 Elected Director in 1985 and Chairman effective March 1995 through March 2001, and Chief Executive Officer effective March 1995 to March 2001. Also served as President from January 1994 to June 1999.
H. Allen Franklin President, Chief Executive Officer and Director Age 56 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.
Elmer B. Harris Executive Vice President and Director Age 61 Elected Director in 1989 and Executive Vice President in 1991. He also has served as President and Chief Executive Officer of ALABAMA since 1989.
David M. Ratcliffe Executive Vice President Age 52 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.
Stephen A. Wakefield Senior Vice President and General Counsel Age 60 Elected in 1997. Previously, he was a partner at the law firm of Akin, Gump, Strauss, Hauer & Feld, LLP from July 1991 through August 1997.
Gale E. Klappa Financial Vice President, Chief Financial Officer and Treasurer Age 50 Elected effective March 1, 2001. Previously served as 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 Vice President Age 49 Elected in 1998; serves as Chief Production Officer for the SOUTHERN system. He also has served as Executive Vice President of GEORGIA since May 1998. Previously, he served as Executive Vice President of ALABAMA from 1994 through April 1998.
W. G. Hairston, III Age 56 President and Chief Executive Officer of Southern Nuclear since 1993.
The officers of SOUTHERN were elected for a term running from the last annual meeting of the directors (May 24, 2000) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Franklin and Mr. Klappa, whose elections were effective on the date indicated.
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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, 2000.
Elmer B. Harris President, Chief Executive Officer and Director Age 61 Elected in 1989. Served as President and Chief Executive Officer since 1989. Elected Executive Vice President of SOUTHERN in 1991. Served as a Director of SOUTHERN since 1989.
Michael D. Garrett Executive Vice President Age 51 Elected in 1998. Served as Executive Vice President of Customer Service since January 2000. Previously served as Executive Vice President of External Affairs from March 1998 to January 2000; and Senior Vice President of External Affairs from February 1994 to March 1998.
William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer Age 57 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 52 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.
Jerry L. Stewart Senior Vice President Age 51 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 28, 2000) for one year until the next annual meeting or until their successors are elected and have qualified.
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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, 2000.
David M. Ratcliffe President, Chief Executive Officer and Director Age 52 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 52 Elected in 1995. Served as Executive Vice President of External Affairs since 1995. Previously served as Senior Vice President of External Affairs from April 1995 to September 1995.
Thomas A. Fanning Executive Vice President, Treasurer and Chief Financial Officer Age 43 Elected in 1999. Previously served as Senior Vice President of SOUTHERN from June 1998 to June 1999; and Senior Vice President and Chief Information Officer for SOUTHERN from March 1995 to 1998.
Gene R. Hodges Executive Vice President Age 62 Elected in 1986. Served as Executive Vice President of Customer Operations, Power Delivery and Safety since 1992.
James K. Davis Senior Vice President Age 60 Elected in 1993. Served as Senior Vice President of Corporate Relations since 1993, with Employee Relations being added to his responsibilities in 2000.
Robert H. Haubein Senior Vice President Age 60 Elected in 1992. Served as Senior Vice President of Fossil/Hydro Power since 1994.
Leonard J. Haynes Senior Vice President Age 50 Elected in 1998. Served as Senior Vice President of Marketing since 1998. Previously served as Vice President of Retail Sales and Services from October 1995 to November 1998.
Fred D. Williams Senior Vice President Age 56 Elected in 1992. Served as Senior Vice President of Resource Policy and Planning since 1998. Previously served as Senior Vice President of Wholesale Power Marketing from 1995 to 1998.
The officers of GEORGIA were elected for a term running from the last annual meeting of the directors (May 17, 2000) for one year until the next annual meeting or until their successors are elected and have qualified.
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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, 2000.
Travis J. Bowden President, Chief Executive Officer and Director Age 62 Elected in 1994. Served as President and Chief Executive Officer since 1994.
Francis M. Fisher, Jr. Vice President Age 52 Elected in 1989. Served as Vice President of Power Delivery and Customer Operations since 1996. Previously served as Vice President of Employee and External Relations from 1989 to 1996.
John E. Hodges, Jr. Vice President Age 57 Elected in 1989. Served as Vice President of Marketing and Employee/External Affairs since 1996. Previously served as Vice President of Customer Operations from 1989 to 1996.
Ronnie R. Labrato Comptroller and Chief Financial Officer Age 47 Elected as an Executive Officer in July 2000. Previously served as Controller from 1992 to 2000.
Robert G. Moore Vice President Age 51 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 Secretary/Treasurer and Regional Chief Information Officer Age 58 Elected as an Executive Officer in July 2000. Served 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 28, 2000) for one year until the next annual meeting or until their successors are elected and have qualified.
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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, 2000.
Dwight H. Evans President, Chief Executive Officer and Director Age 52 Elected in 1995. Previously served as Executive Vice President of External Affairs of GEORGIA from 1989 to 1995.
H. E. Blakeslee Vice President Age 60 Elected in 1984. Served as Vice President of Customer Services and Retail Marketing since 1984.
Don E. Mason Vice President Age 59 Elected in 1983. Served as Vice President of External Affairs and Corporate Services since 1983.
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer Age 48 Elected in 1995. Served as Vice President, Secretary, Treasurer and Chief Financial Officer since 1995.
Gene L. Ussery, Jr. Vice President Age 51 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 26, 2000) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Ussery, whose election was effective on September 21, 2000.
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PART II
Item 5.
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 ----------- --------------
First Quarter $25-7/8 $20-3/8 Second Quarter 27-7/8 21-11/16 Third Quarter 35 23-13/32 Fourth Quarter 33-22/25 27-1/2
First Quarter $29-5/8 $23-1/4 Second Quarter 29-3/16 22-3/4 Third Quarter 28 25 Fourth Quarter 27-1/8 22-1/16
-------------------- --------------- --- --------------
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 28, 2001, the closing price of SOUTHERN's common stock was $30.95.
(b) Number of SOUTHERN's common stockholders at December 31, 2000: 160,116
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 integrated Southeast utilities to their stockholder(s) for the past two years were as follows: (in thousands)
------------------- --------- ------------- ---------- Registrant Quarter 2000 1999 ------------------- --------- ------------- ----------
SOUTHERN First $220,557 $233,879 Second 217,289 233,445 Third 217,289 228,690 Fourth 218,098 225,470
ALABAMA First 103,600 98,000 Second 105,200 98,400 Third 104,400 99,700 Fourth 103,900 103,500
GEORGIA First 136,500 133,100 Second 138,600 133,700 Third 137,600 135,500 Fourth 136,900 140,700
GULF First 14,600 15,000 Second 14,900 15,100 Third 14,800 15,300 Fourth 14,700 15,900
MISSISSIPPI First 13,600 13,800 Second 13,800 13,800 Third 13,700 14,000 Fourth 13,600 14,500
SAVANNAH First 6,100 6,200 Second 6,200 6,200 Third 6,000 6,300 Fourth 6,000 6,500 ------------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of 1999 and 2000. The dividend paid on SOUTHERN's common stock for the first quarter of 2001 was 33.5(cent) per share.
The amount of dividends on their common stock that may be paid by the subsidiary registrants is restricted in accordance with their first mortgage bond indenture. The amounts of earnings retained in the business
II-1
and the amounts restricted against the payment of cash dividends on common stock at December 31, 2000 were as follows:
-------------------- ------------------ --- -------------- Retained Restricted Earnings Amount ------------------ -------------- (in millions)
ALABAMA $1,228 $ 796 GEORGIA 1,788 891 GULF 156 127 MISSISSIPPI 173 118 SAVANNAH 110 68 Consolidated 4,672 2,000
-------------------- ------------------ --- --------------
Item 6.
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-41 and II-42.
ALABAMA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-74 and II-75.
GEORGIA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-109 and II-110.
GULF. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-138 and II-139.
MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-167 and II-168.
SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-194 and II-195.
Item 7.
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-17.
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-46 through II-54.
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-79 through II-87.
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-114 through II-122.
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-143 through II-150.
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-172 through II-178.
Item 7A.
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 for Non-Trading Activities" contained herein on pages II-13 through II-14 and II-28, 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-51, II-83. II-118, II-146, and II-175, respectively.
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Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2000 FINANCIAL STATEMENTS
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT Southern Company and Subsidiary Companies 2000 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 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 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 President and Chief Executive Officer
/s/Gale E. Klappa Gale E. Klappa Financial Vice President, Chief Financial Officer, and Treasurer
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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, 2000 and 1999, 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, 2000. 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-18 through II-40)referred to above present fairly, in all material respects, the financial position of Southern Company and subsidiary companies as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Atlanta, Georgia February 28, 2001
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 2000 Annual Report
RESULTS OF OPERATIONS - ---------------------
OVERVIEW OF CONSOLIDATED EARNINGS
Southern Company's solid financial performance resulted in record earnings for 2000. Higher earnings were driven by both strong growth of selling electricity in the Southeast and by the global subsidiary's competitive energy supply business outside the Southeast. Reported earnings in both 2000 and 1999 reflected significant items not related to the normal day-to-day business activities. After adjusting for these items, earnings per share for 2000 was $2.13 compared with $1.90 in 1999. Earnings as reported and the details of earnings as adjusted are shown in the following table.
In April 2000, Southern Company announced an initial public offering of up to 19.9 percent of Mirant Corporation -- formerly Southern Energy, Inc. -- 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 an initial public offering of 66.7 million shares of common stock.
On February 19, 2001, Southern Company's board of directors approved the spin off of the remaining ownership of 272 million Mirant shares to be completed in a tax free distribution on April 2, 2001. As a result of the spin off, Southern Company financial statements and related information reflect Mirant as discontinued operations.
A reconciliation of reported consolidated earnings, including discontinued operations, to earnings as adjusted -- which exclude non-day to day business items -- and the related explanations are as follows:
Consolidated Earnings Net Income Per Share ---------------- -------------- 2000 1999 2000 1999 --------------- --------------- (in millions) Earnings from -- Continuing operations $ 994 $ 915 $1.52 $1.33 Discontinued operations 319 361 .49 .53 - --------------------------------------------------------------- Earnings as reported 1,313 1,276 2.01 1.86 - --------------------------------------------------------------- Mirant transition costs 80 - .12 - Mobile Energy write down 10 69 .01 .10 Gain on asset sale - (78) - (.11) Work force reductions - 50 - .07 Other (8) (14) (.01) (.02) - --------------------------------------------------------------- Total adjustments 82 27 .12 .04 - --------------------------------------------------------------- Earnings as adjusted $1,395 $1,303 $2.13 $1.90 ===============================================================
Mirant's transition costs shown in the table include charges related to becoming a public company and changes in their tax strategy in Asia.
In 2000 and 1999, Southern Company recorded asset impairment charges related to Mobile Energy Services -- see Note 3 to the financial statements. In 1999, Mirant sold a portion of its business in the United Kingdom. Work force reduction programs began in late 1999 for a German utility in which Mirant has an ownership interest.
SOUTHERN COMPANY BUSINESS ACTIVITIES
Discussion of the results of operations is focused on the traditional business of the integrated Southeast utilities. The remaining portion of Southern Company's other business activities include telecommunications, energy products and services, leveraged leasing activities, as well as the parent holding company. The impact of these other business activities on the consolidated results of operations is not significant. For more information, see Note 12.
Integrated Southeast Utilities
The five integrated Southeast utilities provide electric service in four states. These utilities are Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric. A condensed income statement for these companies is as follows:
Increase (Decrease) Amount From Prior Year ------ -------------------- 2000 2000 1999 -------------------------------------------------------------- (in millions) Operating revenues $9,860 $735 $(238) - --------------------------------------------------------------- Fuel 2,564 236 7 Purchased power 677 268 13 Other operation and maintenance 2,472 41 4 Depreciation and amortization 1,135 89 (277) Taxes other than income taxes 532 11 13 - --------------------------------------------------------------- Total operating expenses 7,380 645 (240) - --------------------------------------------------------------- Operating income 2,480 90 2 Other income, net (18) (11) (84) - --------------------------------------------------------------- Earnings before interest and taxes 2,462 79 (82) Interest expenses and other 650 15 (44) Income taxes 703 28 (28) - --------------------------------------------------------------- Net income $1,109 $ 36 $ (10) ===============================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
Revenues
Operating revenues for the integrated Southeast utilities in 2000 and the amount of change from the prior year are as follows:
Increase (Decrease) Amount From Prior Year ------- -------------------- 2000 2000 1999 - --------------------------------------------------------------- (in millions) Retail -- Base revenues $6,014 $174 $(262) Fuel cost recovery and other 2,599 353 76 - --------------------------------------------------------------- Total retail 8,613 527 (186) - --------------------------------------------------------------- Sales for resale -- Within service area 377 27 (24) Outside service area 600 127 (49) - ---------------------------------------------------------------- Total sales for resale 977 154 (73) Other operating revenues 270 54 21 - --------------------------------------------------------------- Operating revenues $9,860 $735 $(238) =============================================================== Percent change 8.1% (2.5)% - ---------------------------------------------------------------
Base revenues increased $174 million in 2000 as a result of continued customer growth in the traditional service area and the positive impact of weather on energy sales. However, total base revenues of $5.8 billion in 1999 declined as a result of a Georgia Power rate reduction and recorded revenue sharing in 1999. For additional information, see Note 3 to the financial statements under "Georgia Power 1998 Retail Rate Order." Customer growth in the Southeast somewhat offset the rate decrease.
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 economic loss from untimely recovery of these receivables. Each company has filed or will be filing for approval of new fuel rates to be more reflective of escalating fuel costs.
Revenues from sales for resale within the service area were up as a result of additional demand during the hot summer of 2000. Sales for resale revenues within the service area were $350 million in 1999, down 6.5 percent from the prior year. This sharp decline resulted primarily from supplying less electricity under contractual agreements with certain wholesale customers in 1999.
Energy sales for resale outside the service area are principally unit power sales under long-term contracts to Florida utilities. Economy energy and energy under short-term contracts are also sold for resale outside the service area. Revenues from long-term unit 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. The capacity and energy components of the unit power contracts were as follows:
2000 1999 1998 - --------------------------------------------------------------- (in millions) Capacity $177 $174 $196 Energy 178 157 152 - --------------------------------------------------------------- Total $355 $331 $348 ===============================================================
Capacity revenues in 2000 and 1999 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
The changes in revenues for the traditional business in the Southeast are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 2000 and the percent change by year were as follows:
Amount Percent Change (billions of ------ --------------------------- kilowatt-hours) 2000 2000 1999 1998 - --------------------------------------------------------------- Residential 46.2 6.5% (0.2)% 10.9% Commercial 46.2 6.6 4.0 7.2 Industrial 56.7 1.0 1.6 2.1 Other 1.0 2.7 1.6 3.1 ----- Total retail 150.1 4.3 1.7 6.2 Sales for resale -- Within service area 9.6 1.5 (4.1) (0.4) Outside service area 17.2 33.0 (0.4) (5.6) ----- Total 176.9 6.4 1.2 4.7 ===============================================================
The rate of growth in 2000 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 number of residential customers served increased by 59,000 during the year. Commercial and industrial sales, both in
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
2000 and 1999, continued to show slight gains in excess of the national averages. This reflects the strength of business and economic conditions in Southern Company's traditional service area in the southeastern United States. The rate of increase in 1999 total retail energy sales was significantly lower than in 1998. Residential energy sales experienced a decline as a result of milder weather in 1999, which strongly affected the total retail sales increase of 1.7 percent. Energy sales to retail customers are projected to increase at an average annual rate of 2.1 percent during the period 2001 through 2011.
Sales to customers outside the service area under long-term contracts for unit power sales increased 21 percent in 2000 and increased 19 percent in 1999. These changes in sales were influenced by weather and fluctuations in prices for oil and natural gas, 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 2000, operating expenses of $7.4 billion increased $645 million compared with the prior year. The costs to produce electricity for the traditional business in 2000 increased by $498 million to meet higher energy demands. Non-production operation and maintenance expenses increased $47 million in 2000. In 2000, depreciation and amortization expenses increased $89 million of which $50 million resulted from the 1998 Georgia Power rate order as referred to earlier.
In 1999, operating expenses of $6.7 billion decreased $240 million. This decline was driven by a reduction of $277 million accelerated depreciation of plant being recorded primarily as a result of the 1998 Georgia Power rate order. The costs to produce electricity for the traditional business in the Southeast for 1999 increased by $68 million to meet higher energy demands. All other operation and maintenance expenses declined by $44 million.
Fuel costs constitute the single largest expense for the integrated Southeast 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 traditional business service area -- were as follows:
2000 1999 1998 - ------------------------------------------------------------------- Total generation (billions of kilowatt-hours) 174 165 164 Sources of generation (percent) -- Coal 78 78 77 Nuclear 16 17 16 Hydro 2 2 4 Oil and gas 4 3 3 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.51 1.45 1.48 - -------------------------------------------------------------------
In 2000, fuel and purchased power costs increased $504 million 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 last year.
Total fuel and purchased power costs of $2.7 billion in 1999 increased only $20 million while total energy sales increased 2.0 billion kilowatt-hours compared with the amounts recorded in 1998. Continued efforts to control energy costs helped lower the average cost of fuel per net kilowatt-hour generated in 1999.
Total interest charges and other financing costs in 2000 increased $15 million reflecting new generating units being constructed requiring some external financing. Total interest charges and other financing costs in 1999 decreased $44 million from amounts reported in the previous year. The decline reflected additional refinancing of debt in 1999.
Discontinued Operations
Mirant is a global energy company whose businesses include competitive electricity distribution companies, independent power projects, and energy trading and risk management companies.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
On February 19, 2001, Southern Company's board of directors approved the spin off of Mirant, to be effective on April 2, 2001. As a result of this action, Mirant's financial and related information is shown as discontinued operations. All historical financial statements, footnotes, and related disclosures have been reclassified to conform with the current year presentation.
Earnings from discontinued operations are shown net of income taxes and minority interest. Southern Company earnings per share as adjusted was $2.13 in 2000, of which Mirant's earnings as adjusted contributed approximately $0.60 per share. On the same basis in 1999, Southern Company earnings per share was $1.90, of which $0.47 was attributed to Mirant.
Effects of Inflation
Southern Company's traditional business of the integrated Southeast utilities 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 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 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
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 regulated integrated Southeast utilities 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.
The traditional business or the five Southeast utilities currently operate as vertically integrated companies providing electricity to customers within the traditional 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.
Future earnings for the traditional 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 traditional service area.
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 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 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 current energy crisis in California. As a result of this crisis, many states
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
have either discontinued or delayed implementation of initiatives involving retail deregulation. The inability of a company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on 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 Southern Company's integrated Southeast 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 other 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.
On December 20, 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. After participating in regional conferences with customers and other members of the public to discuss the formation of RTOs, utilities were required to make a filing with the FERC. Southern Company filed on October 16, 2000, a proposal for the creation of an RTO. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of Southern Company and any other participating utilities. Participants would have the option to either maintain their ownership, divest, sell, or lease their assets to the proposed RTO. If the FERC accepts the proposal as filed, the creation of an RTO is not expected to have a material impact on Southern Company's financial statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators to sell power largely free of 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 aggressively working to maintain and expand its share of wholesale sales in the southeastern power markets. In January 2001, Southern Company announced the formation of a new subsidiary -- Southern Power Company. The new subsidiary will own, manage, and finance wholesale generating assets in the Southeast. Southern Power will be the primary growth engine for Southern Company's market-based energy business. Energy from its assets will be marketed to wholesale customers under the Southern Company name. By 2005, plans call for Southern Power to have developed or acquired more than 7,500 megawatts dedicated to the competitive wholesale business. Within 10 years, the new wholesale generating company's goal is to own more than 15,000 megawatts.
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, Southern Company recorded non-cash income of approximately $130 million in 2000. Pension plan income in 2001 is expected to be less as a result of plan amendments. Future pension income is dependent on several factors including trust earnings and changes to the plan. For more information, see Note 2.
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."
The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry -- including Southern Company's -- regarding the recognition, measurement, and classification in the financial statements of decommissioning costs for nuclear generating facilities. In response to these questions, the Financial Accounting Standards Board (FASB) is reviewing the accounting for liabilities related to the retirement of long-lived
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
assets, including nuclear decommissioning. If the FASB issues new accounting rules, the estimated costs of retiring Southern Company's nuclear and other facilities may be required to be recorded as liabilities in the Consolidated Balance Sheets. Also, the annual provisions for such costs could change. Because of the company's current ability to recover asset retirement costs through rates, these changes would not have a significant adverse effect on results of operations. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information.
The integrated Southeast utilities 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 Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. Statement No. 133 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.
Southern Company utilizes financial instruments to reduce its exposure to changes in interest rates and foreign currency exchange rates. Southern Company also enters into commodity related forward contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales.
Substantially all of these bulk energy purchases and sales meet the definition of a derivative under Statement No. 133. In many cases, these transactions meet the normal purchase and sale exception and the related contracts will continue to be accounted for under the accrual method. Certain of these instruments qualify as cash flow hedges resulting in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness will be recognized currently in net income. However, others will be required to be marked to market through current period income.
Southern Company adopted Statement No. 133 effective January 1, 2001. The cumulative effect of adoption was a reduction of approximately $300 million in comprehensive income, which was all related to discontinued operations. The impact on net income was immaterial. The application of the new rules is still evolving and further guidance from FASB is expected, which could additionally impact Southern Company's financial statements. Also, as wholesale energy markets mature, the accounting for future transactions could be significantly impacted by Statement No. 133, resulting in more volatility in net income and comprehensive income.
FINANCIAL CONDITION - ------------------
Overview
Southern Company's financial condition continues to remain strong. In 2000, the integrated Southeast utilities' earnings were at the high end of their respective allowed range of return on equity. Also, earnings from discontinued operations made a solid contribution. These factors drove the reported consolidated net income to a record $1.31 billion in 2000. The quarterly dividend declared in January 2001 was 33 1/2 cents per share, or $1.34 annually. Southern Company is committed to a goal of maintaining its current annual dividend of $1.34 per share and to grow the dividend over time consistent with earnings expectations. After the Mirant spin off, Southern Company's target will be to grow earnings per share at an average annual rate of 3 to 5 percent.
Gross property additions to utility plant from continuing operations were $2.2 billion in 2000. The majority of funds needed for gross property additions since 1997 has been provided from operating activities. The Consolidated Statements of Cash Flows provide additional details.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
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. Generally, company policy is that derivatives are to be used only 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 versus the previous reporting period. In addition, the company is not aware of any facts or circumstances that would significantly impact such exposures in the near-term.
If the company sustained a 100 basis point change in interest rates for all variable rate debt, the change would affect annualized interest expense by approximately $23 million at December 31, 2000. Based on the company's overall interest rate exposure at December 31, 2000, 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 integrated Southeast utilities 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, the companies enter 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, 2000, exposure from these activities was not material to the consolidated financial statements.
For additional information, see Note 1 to the financial statements under "Financial Instruments for Non-Trading Activities."
Capital Structure
During 2000, the integrated Southeast utilities sold, through public authorities, $79 million of pollution control revenue bonds. In addition, senior notes of $650 million were issued in 2000. The companies continued to reduce financing costs by retiring higher-cost securities. Retirements of bonds and senior notes, including maturities, totaled $298 million during 2000, $1.2 billion during 1999, and $1.7 billion during 1998. Retirements of preferred stock totaled $86 million during 1999 and $239 million during 1998.
In December 2000, Southern Company issued 28 million treasury shares of common stock through a public offering. The offering raised $800 million and was priced at $28.50 per share. The proceeds were used to reduce debt.
In April 1999, Southern Company announced the repurchase of up to 50 million shares of its 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. Funding for the program was provided from Southern Company's commercial paper program. At the close of 2000, the company's common stock market value was 33 1/4 per share, compared with book value of $15.69 per share. The market-to-book value ratio was 212 percent at the end of 2000, compared with 170 percent at year-end 1999, and 207 percent at year-end 1998.
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $2.9 billion for 2001, $2.6 billion for 2002, and $1.7 billion for 2003. 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 6,300 megawatts of new generating capacity scheduled to be placed in service by 2003. Approximately 4,100 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 for the traditional business in the Southeast.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $1.4 billion will be required by the end of 2003 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.
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 the integrated Southeast utilities 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 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 the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. The EPA did not include the system service company in the new complaint. Southern Company believes that its integrated utilities 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 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 and some 50 generating units were brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required 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.
The one-hour ozone non-attainment standards for the Atlanta and Birmingham areas have been set and must be implemented in May 2003. Seven generating plants will be affected in the Atlanta area and two plants in the Birmingham area. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $935 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
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 recently dismissed certain challenges but 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 will address other legal challenges to these standards in mid-2001. If the standards are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May 31, 2004. The final rule affects 21 states, including Alabama and Georgia. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $195 million.
In December 2000, the EPA completed its utility studies 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 (MACT) provisions of the Clean Air Act. This determination is being challenged in the courts. 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 BART rules is probable in the near future.
Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C. add to the uncertainties associated with BART guidance and the MACT determination for mercury and other HAPS.
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; 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 costs and have recognized in their respective financial statements costs to clean up known sites. These costs for Southern Company amounted to $4 million in 2000, $4 million in 1999, and $6 million in 1998. 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 a site in Brunswick, Georgia.
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 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2000 Annual Report
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 2001 -- 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 integrated Southeast utilities 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 2001 approximately $199 million of cash and cash equivalents and $5.1 billion of unused credit arrangements with banks.
Cautionary Statement Regarding Forward-Looking Information
Southern Company's 2000 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 earnings per share and earnings growth goals. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "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 Georgia Power and potentially other of Southern Company's subsidiaries and the race discrimination litigation against certain of Southern Company's subsidiaries; the extent and timing of the entry of additional competition in the markets of Southern Company's subsidiaries; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; internal restructuring or other restructuring options, that may be pursued by Southern Company; state and federal rate regulation in the United States and in foreign countries in which Southern Company's subsidiaries operate; political, legal and economic conditions and developments in the United States and in foreign countries in which Southern Company's subsidiaries operate; financial market conditions and the results of financing efforts; the impact of fluctuations in commodity prices, interest rates and customer demand; weather and other natural phenomena; the performance of projects undertaken by the non-traditional business and the success of efforts to invest in and develop new opportunities; 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; developments in the California power markets, including, but not limited to, governmental intervention, deterioration in the financial condition of counterparties, default on receivables due, adverse results in current or future litigation and adverse changes in the tariffs of the California Power Exchange Corporation or the California Independent System Operator Corporation; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by Southern Company with the SEC.
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NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 2000 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of five integrated Southeast utilities, a system service company, Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern Nuclear), Mirant Corporation -- formerly Southern Energy, Inc. -- and other direct and indirect subsidiaries. The integrated Southeast utilities -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four states. Contracts among the integrated Southeast utilities -- 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 subsidiary companies. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Mirant acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Mirant businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States. As a result of the approved spin off of Mirant, Southern Company's financial statements and related information, both current and historical, 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 integrated Southeast utilities 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 integrated Southeast utilities 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:
2000 1999 - --------------------------------------------------------------- (in millions) Deferred income tax charges $ 957 $ 987 Premium on reacquired debt 280 302 Department of Energy assessments 46 52 Vacation pay 92 87 Postretirement benefits 30 33 Deferred income tax credits (551) (640) Accelerated amortization (220) (85) Storm damage reserves (34) (29) Other, net 116 144 - --------------------------------------------------------------- Total $ 716 $ 851 ===============================================================
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.
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NOTES (continued) Southern Company and Subsidiary Companies 2000 Annual Report
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 integrated Southeast utilities 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.
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 $136 million in 2000, $137 million in 1999, and $133 million in 1998. 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 fuel in January 1998 as required by the contracts, and the companies are pursuing legal remedies against the government for breach of contract. Effective June 2000, an on-site dry storage facility for Plant Hatch became operational. Sufficient capacity is believed to be available to continue dry storage operations at Plant Hatch through the life of the plant. Sufficient fuel storage capacity currently is available at Plant Vogtle to maintain full-core discharge capability for both units into the year 2014. 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. Alabama Power and Georgia Power -- based on its ownership interests -- estimate their respective remaining liability at December 31, 2000, under this law to be approximately $25 million and $19 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 in both 2000 and 1999 and 3.3 percent in 1998. 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 $135 million in 2000, $85 million in 1999, and $314 million in 1998. See Note 3 under "Georgia Power 1998 Retail Rate Order" for additional information.
The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial 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
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NOTES (continued) Southern Company and Subsidiary Companies 2000 Annual Report
of December 31, 2000, 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.
Georgia Power has filed with the NRC an application requesting a 20-year renewal of the licenses for both units at Plant Hatch, which would permit the operation of both units until 2034.
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the respective state public service commissions. The amount expensed in 2000 and fund balances were as follows:
Plant Plant Plant Farley Hatch Vogtle - --------------------------------------------------------------- (in millions) Amount expensed in 2000 $ 18 $ 19 $ 9 Accumulated provisions: External trust funds, at fair value $314 $230 $146 Internal reserves 38 20 12 - --------------------------------------------------------------- Total $352 $250 $158 ===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site study. Effective January 1, 1999, the Georgia Public Service Commission (GPSC) increased Georgia Power's annual provision for decommissioning expenses TO $28 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 1997. The estimates are $526 million and $438 million for plants Hatch and Vogtle, respectively. The ultimate costs associated with the 1997 NRC minimum funding requirements are $1.1 billion and $1.3 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.
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 used during construction was $71 million in 2000, $36 million in 1999, and $19 million in 1998. 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.
Leveraged Leases
Southern Company has several leveraged lease agreements -- ranging up to 30 years -- that primarily relate to energy generation, distribution, and transportation assets. The investment income earned from these leveraged leases is immaterial for all periods presented.
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NOTES (continued) Southern Company and Subsidiary Companies 2000 Annual Report
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 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 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 foreign currency translation adjustments, net of taxes -- is presented in the consolidated financial statements. The objective of the statement 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 for Non-Trading Activities
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.
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 company is unaware of any counterparties that will fail to meet their obligations.
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 notional amount is 32 million euros maturing in 2001 through 2002. At December 31, 2000, the unrecognized gain on these swaps was approximately $3 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, 2000 $7,815 $7,702 At December 31, 1999 7,483 7,046 Capital and preferred securities: At December 31, 2000 2,246 2,190 At December 31, 1999 2,246 1,942 - ------------------------------------------------------------------
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 defined benefit, trusteed, pension plans that cover substantially all employees. Southern 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 integrated Southeast utilities fund trusts to the extent required by their respective regulatory commissions. In late 2000, Southern Company adopted several pension and postretirement benefits plan changes that had the effect of increasing benefits to both current and future retirees. The effects of these changes will be to increase annual pension and postretirement benefits costs by approximately $28 million and $26 million, respectively.
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NOTES (continued) Southern Company and Subsidiary Companies 2000 Annual Report
The measurement date for plan assets and obligations is September 30 for each year. The following disclosures exclude discontinued operations.
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 --------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $3,098 $3,084 Service cost 94 95 Interest cost 227 204 Benefits paid (145) (143) Actuarial (gain) loss (28) (142) - ---------------------------------------------------------------- Balance at end of year $3,246 $3,098 ================================================================
Plan Assets ------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $5,266 $4,646 Actual return on plan assets 1,030 771 Benefits paid (139) (151) - ---------------------------------------------------------------- Balance at end of year $6,157 $5,266 ================================================================
The accrued pension costs recognized in the Consolidated Balance as follows:
2000 1999 - --------------------------------------------------------------- (in millions) Funded status $ 2,911 $ 2,168 Unrecognized transition obligation (64) (77) Unrecognized prior service cost 97 106 Unrecognized net gain (2,446) (1,829) - --------------------------------------------------------------- Prepaid asset recognized in the Consolidated Balance Sheets $ 498 $ 368 ===============================================================
Components of the pension plans' net periodic cost were as follows:
2000 1999 1998 - -------------------------------------------------------------- (in millions) Service cost $ 94 $ 95 $ 86 Interest cost 227 204 204 Expected return on plan assets (384) (348) (320) Recognized net gain (64) (41) (47) Net amortization (3) (4) (3) - -------------------------------------------------------------- Net pension cost (income) $(130) $ (94) $ (80) ==============================================================
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 -------------------- 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $ 980 $1,029 Service cost 18 21 Interest cost 76 68 Benefits paid (43) (36) Actuarial (gain) loss 21 (102) - --------------------------------------------------------------- Balance at end of year $1,052 $ 980 ===============================================================
Plan Assets ------------------ 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $395 $336 Actual return on plan assets 47 36 Employer contributions 59 60 Benefits paid (42) (37) - --------------------------------------------------------------- Balance at end of year $459 $395 ===============================================================
The accrued postretirement costs recognized in the Consolidated Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in millions) Funded status $(593) $(585) Unrecognized transition obligation 189 203 Unrecognized prior service cost 66 - Unrecognized net loss (gain) (53) 10 Fourth quarter contributions 35 26 - --------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $(356) $(346) ===============================================================
Components of the postretirement plans' net periodic cost were as follows:
2000 1999 1998 - -------------------------------------------------------------- (in millions) Service cost $ 18 $ 21 $ 18 Interest cost 76 68 68 Expected return on plan assets (34) (26) (21) Recognized net gain - 2 2 Net amortization 18 15 15 - -------------------------------------------------------------- Net postretirement cost $ 78 $ 80 $ 82 ==============================================================
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NOTES (continued) Southern Company and Subsidiary Companies 2000 Annual Report
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits were:
2000 1999 - --------------------------------------------------------------- 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 7.29 percent for 2000, decreasing gradually to 5.50 percent through the year 2005, 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, 2000 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $71 $63 Service and interest costs 6 6 - ---------------------------------------------------------------
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 2000, 1999, and 1998 were $49 million, $46 million, and $43 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power and four other unrelated entities were notified by the Environmental Protection Agency (EPA) that they have been designated as potentially responsible parties under the Comprehensive Environmental Response, Compensation, and Liability Act with respect to a site in Brunswick, Georgia. As of December 31, 2000, Georgia Power had recorded approximately $5 million in cumulative expenses associated with Georgia Power's agreed-upon share of the removal and remedial investigation and feasibility study costs for this site.
The final outcome of this matter cannot now be determined. However, based on the nature and extent of Georgia Power's activities relating to the site, management believes that the company's portion of any remaining remediation costs should not be material to the financial statements.
Environmental Litigation
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 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, 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 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 the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. The EPA did not include the system service company in the new complaint. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place.
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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.
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 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, 2000, MESH had total assets of $373 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, 2000, 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, 2000. 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 bankruptcy court. The proposed plan of reorganization was again amended on February 21, 2001. Changes in circumstances since the filing of the amended plan may require further modifications of the plan. Southern Company expects that approval of a plan of reorganization would result in a termination of Southern Company's ownership interest in MESH, but would not affect Southern Company's continuing guarantee obligations described earlier. The final outcome of this matter cannot now be determined.
California Electricity Markets Litigation
Five lawsuits have been 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. Four of the suits seek class action status. One lawsuit naming Southern Company, Mirant, and other generators as defendants alleges that, as a result of the defendants' conduct, customers paid approximately $4 billion more for electricity than they otherwise would have and seeks an award of treble damages, as well as other injunctive and equitable relief. The other suits likewise seek treble damages and equitable relief. While two of the suits name Southern Company as a defendant, it appears that the allegations, as they may relate to Southern Company, are directed to activities of subsidiaries of Mirant. One such suit names Mirant itself as a defendant. Southern Company has notified Mirant of its claim for indemnification for costs associated with these actions under the terms of the master separation agreement that governs the spin off of Mirant. Mirant has undertaken the defense of all of the claims. The final outcome of these lawsuits cannot now be determined.
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 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 and a new defendant, Southern Company Energy Solutions, Inc. The lawsuit is in the discovery phase. The final outcome of this matter 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
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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. 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. There is a moratorium on any periodic retail rate increases (but not decreases) until July 2001.
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. In April 1997, the APSC issued an additional order authorizing Alabama Power to reduce balance sheet asset items. This order authorizes the reduction of such items up to an amount equal to five times the total estimated annual revenue reduction resulting from future rate reductions initiated by Alabama Power. In 1998, Alabama Power -- in accordance with the 1995 rate order -- recorded $33 million of additional amortization of premium on reacquired debt. Alabama Power did not record any additional amounts in 2000 or 1999.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
Georgia Power 1998 Retail Rate Order
As required by the GPSC, Georgia Power filed a general rate case in 1998. On December 18, 1998, the GPSC approved a three-year rate order for Georgia Power ending December 31, 2001. Under the terms of the order, Georgia Power's earnings will continue to be evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Georgia Power's annual retail rates were decreased by $262 million effective January 1, 1999, and by an additional $24 million effective January 1, 2000. In addition, the order provided for $85 million annually to be applied to accelerated amortization or depreciation of assets, and up to an additional $50 million annually in 2000 and 2001 of any earnings above the 12.5 percent return. In accordance with the rate order, Georgia Power recorded accelerated amortization of $135 million and $85 million in 2000 and 1999, respectively. In May 2000, the GPSC ordered that these funds be maintained in a regulatory liability account and ordered that interest be accrued on this account at the prime rate. In 2000, interest of $10 million was recorded. These amounts are reflected on the balance sheets in deferred credits and other liabilities, other.
Two-thirds of any additional earnings above the 12.5 percent return in any year will be applied to rate reductions and the remaining one-third retained by Georgia Power. In both 2000 and 1999, Georgia Power's return was above 12.5 percent, and accordingly, it recorded in 1999 $79 million of revenues to be refunded to customers in 2000. In 2000, Georgia Power recorded $44 million as an estimate of revenues to be refunded in 2001. Georgia Power is required to file a general rate case on July 1, 2001. At that time, the GPSC is expected to determine whether the rate order should be continued, modified, or discontinued.
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.
At December 31, 2000, 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% $3,301 $1,724 Plant Hatch (nuclear) 50.1 873 650 Plant Miller (coal) Units 1 and 2 91.8 743 312 Plant Scherer (coal) Units 1 and 2 8.4 112 53 Plant Wansley (coal) 53.5 300 150 Rocky Mountain (pumped storage) 25.4 169 72 Intercession City (combustion turbine) 33.3 11 1 - ---------------------------------------------------------------
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Alabama Power and Georgia 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 integrated Southeast utilities 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 2000 with a minimum of three years notice -- until the expiration of the contracts in 2010. Capacity revenues from unit power sales amounted to $177 million in 2000, $174 million in 1999, and $196 million in 1998.
During 2000, Georgia Power and Mississippi Power entered into certain operating leases for portions of their generating unit capacity. Capacity revenues from these operating leases amounted to $20 million in 2000 and are included in the financial statements as sales for resale. Minimum future capacity revenues from noncancelable operating leases as of December 31, 2000 are as follows:
Year Amounts - ----- ----------- (in millions) 2001 $ 53 2002 66 2003 66 2004 66 2005 27 2006 and thereafter 114 - ---------------------------------------------------------------- Total $392 ================================================================
6. Income Taxes
At December 31, 2000, the tax-related regulatory assets and liabilities were $957 million and $551 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:
2000 1999 1998 - --------------------------------------------------------------- (in millions) Total provision for income taxes: Federal -- Current $ 421 $ 504 $ 548 Deferred 95 11 23 - --------------------------------------------------------------- 516 515 571 - --------------------------------------------------------------- State -- Current 71 85 102 Deferred 1 (1) (3) - --------------------------------------------------------------- 72 84 99 - --------------------------------------------------------------- Total $ 588 $ 599 $ 670 ===============================================================
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:
2000 1999 - --------------------------------------------------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $3,199 $3,088 Property basis differences 1,105 1,175 Other 650 444 - --------------------------------------------------------------- Total 4,954 4,707 - --------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 111 113 Other property basis differences 206 221 Deferred costs 190 102 Pension and other benefits 125 121 Other 231 198 - --------------------------------------------------------------- Total 863 755 - --------------------------------------------------------------- Net deferred tax liabilities 4,091 3,952 Portion included in current assets, net (17) (68) - --------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheets $4,074 $3,884 ===============================================================
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
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in 2000, $30 million in 1999, and $38 million in 1998. At December 31, 2000, all investment tax credits available to reduce federal income taxes payable had been utilized.
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:
2000 1999 1998 - --------------------------------------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.8 3.8 Non-deductible book depreciation 1.7 1.9 4.0 Difference in prior years' deferred and current tax rate (1.3) (1.3) (1.3) Other (2.1) (0.3) (1.6) - --------------------------------------------------------------- Effective income tax rate 36.7% 39.1% 39.9% ===============================================================
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.
7. Common Stock
Stock Issued and Repurchased
The amount and timing of additional equity capital to be raised in 2001 -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. Equity capital may be provided from any combination of public offerings, private placements, or the company's stock plans.
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. Funding for the program was provided from Southern Company's commercial paper program.
Shares Reserved
At December 31, 2000, a total of 59 million shares was reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Performance Stock Plan.
Performance Stock Plan
The performance stock plan provides non-qualified stock options to a large segment of Southern Company's employees ranging from line management to executives. As of December 31, 2000, 5,744 current and former employees participated in the plan. The maximum number of shares of common stock that may be issued under the plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. 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 activity in 1999 and 2000 for the plan is summarized below:
Shares Average Subject Option Price To Option Per Share - --------------------------------------------------------------- Balance at December 31, 1998 6,445,398 $22.77 Options granted 2,108,818 26.56 Options canceled (28,630) 25.48 Options exercised (56,708) 19.51 - --------------------------------------------------------------- Balance at December 31, 1999 8,468,878 23.73 Options granted 6,977,038 23.25 Options canceled (226,597) 23.66 Options exercised (984,897) 21.63 - --------------------------------------------------------------- Balance at December 31, 2000 14,234,422 $23.63 =============================================================== Shares reserved for future grants: At December 31, 1998 36,598,001 At December 31, 1999 34,515,156 At December 31, 2000 27,750,261 - --------------------------------------------------------------- Options exercisable: At December 31, 1999 4,525,349 At December 31, 2000 5,898,698 - ---------------------------------------------------------------
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.
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The following table summarizes information about options outstanding at December 31, 2000:
Price Range of Options -------------------------- 14-20 21-24 25-28 - -------------------------------------------------------------- Outstanding: Shares (in thousands) 430 10,217 3,587 Average remaining life (in years) 2.5 8.2 8.1 Average exercise price $17.36 $22.79 $26.77 Exerciseable: Shares (in thousands) 424 3,653 1,822 Average exercise price $17.64 $21.96 $26.84 - --------------------------------------------------------------
The estimated fair values of stock options granted in 2000, 1999 and 1998 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:
2000 1999 1998 - ----------------------------------------------------------------- Interest rate 6.7% 5.8% 5.5% Average expected life of stock options (in years) 4.0 3.7 3.7 Expected volatility of common stock 20.9% 20.7% 19.2% Expected annual dividends on common stock $1.34 $1.34 $1.34 Weighted average fair value of stock options granted $3.36 $4.61 $4.27 - -----------------------------------------------------------------
The pro forma impact on earnings of fair-value accounting for options granted - -- as required by FASB Statement No. 123, Accounting for Stock-Based Compensation -- is 1.2 cents per share in 2000 and less than 1 cent in both 1999 and 1998.
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 Performance Stock 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 ------------------------------- 2000 1999 1998 - --------------------------------------------------------------- (in thousands) As reported shares 653,086 685,163 696,944 Effect of options 1,108 580 739 - --------------------------------------------------------------- Diluted shares 654,194 685,743 697,683 ===============================================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2000, consolidated retained earnings included $3.5 billion of undistributed retained earnings of the subsidiaries. Of this amount, $2.0 billion was restricted against the payment by the subsidiary companies of cash dividends on common stock under terms of bond indentures.
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, 2000, capital securities of $950 million and preferred securities of $1.3 billion were outstanding. Southern Company guarantees the notes related to $950 million of capital or preferred securities issued on its behalf.
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:
2000 1999 - -------------------------------------------------------------- (in millions) Bond improvement fund requirements $11 $ 14 Less: Portion to be satisfied by certifying property additions 11 9 - -------------------------------------------------------------- Cash requirements - 5 First mortgage bond maturities and redemptions - 200 Other long-term debt maturities 67 124 - -------------------------------------------------------------- Total $67 $329 ==============================================================
The first mortgage bond improvement fund requirements amount to 1 percent of each outstanding series of bonds authenticated under the indentures prior to
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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 166 2/3 percent of such requirements.
With respect to the collateralized pollution control revenue bonds, the integrated Southeast utilities 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 2005 applicable to other long-term debt are as follows: $67 million in 2001; $489 million in 2002; $479 million in 2003; $323 million in 2004; and $600 million in 2005.
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. 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 2001, unused credit arrangements with banks totaled $5.1 billion, of which $3.2 billion expires during 2001, $1.0 billion during 2002, and $900 million during 2003 and 2004. The following table outlines the credit arrangements by company:
Amount of Credit ----------------------------------- Expires --------------- 2002 & Company Total Unused 2001 beyond - ------- ------------------------------------ (in millions) Alabama Power $ 925 $ 925 $ 535 $ 390 Georgia Power 1,765 1,765 1,265 500 Gulf Power 123 115 115 - Mississippi Power 117 117 117 - Savannah Electric 65 50 40 10 Southern Company 2,100 2,100 1,100 1,000 Other 60 51 51 - - -------------------------------------------------------------- Total $5,155 $5,123 $3,223 $1,900 ==============================================================
Approximately $2.9 billion of the credit facilities 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. Of the total $5.1 billion in unused credit, $2.1 billion, $1.65 billion, and $780 million are syndicated credit arrangements of Southern Company, Georgia Power, and Alabama Power, respectively. These facilities also 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, 2000, was $1.6 billion.
Southern Company, Alabama Power, and Georgia Power 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.
9. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently estimated to total $2.9 billion in 2001, $2.6 billion in 2002, and $1.7 billion in 2003. 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, 2000, significant purchase commitments were outstanding in connection with the construction program. Southern Company has approximately 6,300 megawatts of additional generating capacity scheduled to be placed in service by 2003.
See Management's Discussion and Analysis under "Environmental Matters" for
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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. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated long-term obligations at December 31, 2000, were as follows:
Purchased Year Fuel Power - ---- ------------------------- (in millions) 2001 $ 2,481 $ 81 2002 1,897 97 2003 1,711 99 2004 1,328 95 2005 1,055 95 2006 and thereafter 3,764 693 - -------------------------------------------------------------- Total commitments $12,236 $1,160 ==============================================================
Operating Leases
Southern Company has operating lease agreements with various terms and expiration dates. These expenses totaled $42 million, $35 million, and $26 million for 2000, 1999, and 1998, respectively. At December 31, 2000, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts - ---- ------------ (in millions) 2001 $ 57 2002 71 2003 71 2004 68 2005 64 2006 and thereafter 388 - -------------------------------------------------------------- Total minimum payments $719 ==============================================================
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, 2000, the total notional amount of guarantees was $419 million and the estimated fair value of net contractual commitments outstanding was approximately $259 million. 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.
At December 31, 2000, Southern Company had guaranteed $11 million related to a Mirant purchase power agreement. The guarantee expires March 2001. Southern Company also has guaranteed certain of Mirant's foreign currency swap transactions. At December 31, 2000, notional amounts under these swaps were the differences between (pound)44 million and $68 million and between DM370 million and $206 million; however, due to favorable exchange ratesSouthern Company had no exposure under these guarantees. The sterling and deutsche mark swaps expire in 2002 and 2003, respectively.
After the spin off, Mirant will pay Southern Company a monthly fee of 1 percent on the average aggregate maximum principal amount of all guarantees outstanding until they are replaced or expire. Southern Company's guarantees related to Mirant trading and marketing activities are limited to a maximum of $425 million, with any guarantees since October 2, 2000 expiring no later than October 2, 2001. 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 private insurance, 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.
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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 be insured against increased costs of replacement power in an amount up to $3.5 million per week -- starting 12 weeks after the outage -- for one year and up to $2.8 million per week for the second and third 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 $17 million and $19 million, respectively.
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.
11. DISCONTINUED 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 an 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, Southern Company's board of directors approved the spin off of its remaining ownership of 272 million Mirant shares to be completed in a tax free distribution on April 2, 2001. Shares from the spin off will be distributed at a ratio of approximately 0.4 for every share of Southern Company common stock held at record date.
As a result of the spin off, Southern Company's December 31, 2000, financial statements have been prepared with Mirant's results of operations and cash flows shown as discontinued operations. All historical financial statements presented and footnotes have been reclassified to conform to this presentation, with the historical assets and liabilities of Mirant presented on the balance sheet as net assets of discontinued operations.
Summarized financial information for the discontinued operations is as follows at December 31:
2000 1999 1998 - --------------------------------------------------------------- (in millions) Revenues $13,315 $2,265 $1,819 Income taxes 86 127 (121) Net income 319 361 (9) - ---------------------------------------------------------------
2000 1999 - --------------------------------------------------------------- (in millions) Current assets $ 9,057 $ 1,254 Total assets 22,377 12,191 Current liabilities 9,726 3,169 Total liabilities 17,585 8,473 Minority and other interests 1,472 805 Net assets of discontinued operations 3,320 2,913 - ---------------------------------------------------------------
12. SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segment is the five integrated Southeast utilities that provide electric service in four states. 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
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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:
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ALABAMA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Alabama Power Company 2000 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 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/Elmer B. Harris Elmer B. Harris President and Chief Executive Officer
/s/William B. Hutchins, III William B. Hutchins, III Executive Vice President, Chief Financial Officer, and Treasurer
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANT
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, 2000 and 1999, 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, 2000. 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-55 through II-73) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Birmingham, Alabama February 28, 2001
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 2000 net income after dividends on preferred stock was $420 million, representing a $20 million (5 percent) increase from the prior year. This improvement is primarily attributable to an increase in territorial sales partially offset by increased non-fuel operating expenses.
In 1999, earnings were $400 million, representing a 6 percent increase from the prior year. This increase was due to a decrease in amortization related to premiums paid to reacquire debt pursuant to an Alabama Public Service Commission (APSC) order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details.
The return on average common equity for 2000 was 13.58 percent compared to 13.85 percent in 1999, and 13.63 percent in 1998.
Revenues
Operating revenues for 2000 were $3.7 billion, reflecting an increase from 1999. The following table summarizes the principal factors that have affected operating revenues for the past two years:
Increase (Decrease) Amount From Prior Year ---------------------------------------- 2000 2000 1999 - ------------------------------------------------------------------- (in thousands) Retail -- Base revenues $2,108,939 $ 80,264 $ 10,022 Fuel cost recovery and other 843,768 61,326 20,418 - ------------------------------------------------------------------- Total retail 2,952,707 141,590 30,440 - ------------------------------------------------------------------- Sales for resale -- Non affiliates 461,730 46,353 (33,596) Affiliates 166,219 73,780 (11,123) - ------------------------------------------------------------------- Total sales for resale 627,949 120,133 (44,719) Other operating revenues 86,805 20,264 13,380 - ------------------------------------------------------------------- Total operating revenues $3,667,461 $281,987 $ (899) =================================================================== Percent change 8.33% (0.03)% - --------------------------------------------------------------------
Retail revenues of $3.0 billion in 2000 increased $142 million (5 percent) from the prior year, compared with an increase of $30 million (1.1 percent) in 1999. The primary contributors to the increase in revenues in 2000 were the positive impact of weather on energy sales, continued economic growth in the Company's service territory, and an increase in fuel revenues. 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. Higher natural gas prices and decreased hydro production combined with increased costs of purchased power have resulted in a large under-recovery of fuel costs at December 31, 2000. Effective January 2001, the Company's fuel rate was increased to address this under-recovery. The Company expects to significantly reduce this balance over a three-year period.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report
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.
Retail revenues in 1999 increased $30 million (1.1 percent) over 1998. The predominant factors causing the rise in revenues in 1999 were continued growth in the Company's service territory, as well as an increase in fuel revenues. These increases were offset by the effect of milder temperatures in 1999 as compared to 1998.
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:
2000 1999 1998 --------------------------------------- (in millions)
Capacity $127 $122 $142 Energy 128 112 118 -------------------------------------------------------- Total $255 $234 $260 ========================================================
Capacity revenues from non-affiliates were relatively unchanged in 2000 compared to the prior year. Capacity revenues from non-affiliates in 1999 decreased 13.9 percent compared to 1998. This decrease was attributable to the lowering of the equity return under formula rate contracts, as well as other adjustments and true-ups related to contractual pricing.
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 2000 and the percent change by year were as follows:
KWH Percent Change -------------------------------------- 2000 2000 1999 -------------------------------------- (millions)
Residential 16,772 6.8% (0.6)% Commercial 12,989 5.5 3.4 Industrial 22,101 0.7 1.7 Other 206 2.3 2.3 ------------ Total retail 52,068 3.8 1.4 Sales for resale - Non-affiliates 14,848 19.4 5.0 Affiliates 5,369 6.7 (15.8) ------------ Total 72,285 6.9% 0.5% - ---------------------------------------------------------------
The increases in 2000 and 1999 retail energy sales were primarily due to the strength of business and economic conditions in the Company's service area. In 2000, 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. Assuming normal weather, sales to retail customers are projected to grow approximately 2.9 percent annually on average during 2001 through 2005.
Expenses
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.
In 1999, total operating expenses of $2.5 billion decreased $13 million or 0.5 percent compared with 1998. This decline was mainly due to a $15 million net decrease in fuel and purchased power costs and a $23 million decrease in maintenance expense, offset by an increase in taxes other than income taxes of $12 million.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 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:
-------------------------- 2000 1999 1998 -------------------------- Total generation (billions of KWHs) 65 63 63 Sources of generation (percent) -- Coal 72 72 72 Nuclear 19 20 18 Hydro 3 5 8 Oil & Gas 6 3 2 Average cost of fuel per net KWH generated (cents) -- 1.54 1.44 1.54 - --------------------------------------------------------------
In 2000, total fuel and purchased power costs of $1.3 billion increased $183 million (16 percent), while total energy sales increased 4,658 million kilowatt hours (6.9 percent) compared with the amounts recorded in 1999. Fuel and purchased power costs in 1999 decreased $15 million (1 percent) compared to 1998.
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 2000, purchased power transactions among the Company and non-affiliates increased $72 million (77 percent) due to higher costs associated with these energy purchases and to offset decreased hydro generation, which was down significantly compared to 1999 as a result of lower stream flows.
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. The 7.5 percent decrease in maintenance expenses in 1999 is primarily attributable to a decrease in distribution expenses.
Depreciation and amortization expense increased 4.9 percent in 2000 and 2.6 percent in 1999. These increases reflect additions to property, plant, and equipment.
Taxes other than income taxes increased $5 million (2.5 percent) in 2000 as compared to 1999. This increase is attributable to increases in real and personal property taxes and public utility license taxes.
Total net interest and other charges increased $7 million (2.7 percent) in 2000. This increase results primarily from an increase in interest on long-term debt offset by a decrease in other interest charges. Total net interest and other charges decreased $38 million (12.3 percent) in 1999 primarily from a decrease in the amortization of premiums on reacquired debt pursuant to an APSC order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details.
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
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 of the Company to achieve energy sales growth while containing cost in a more competitive environment.
The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report
state of Alabama. Prices for electricity provided by the Company to retail customers are set by the APSC under cost-based regulatory principles.
Future earnings for the traditional 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 Company's traditional service area.
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 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 various restructuring and 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 current energy crisis in California. As a result of this crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. The inability of the Company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on the Company's financial statements.
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.
On December 20, 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. After participating in the regional conferences with customers and other members of the public to discuss the formation of RTOs, utilities were required to make a filing with the FERC. Southern Company and its integrated southeast utility subsidiaries, including the Company, filed on October 16, 2000, a proposal for the creation of an RTO. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of the Company and any other participating utilities. Participants would have the option to either maintain their ownership, divest, sell, or lease their assets to the proposed RTO. If the FERC accepts the proposal as filed, the creation of an RTO is not expected to have a material impact on the Company's financial statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators to sell power largely free of regulation under PUHCA. These entities are able to own and operate power generating facilities and sell power to affiliates--under certain restrictions.
The Company is constructing 1,230 megawatts of wholesale generating facilities in Autaugaville, Alabama to begin operation in 2003. Half of this capacity has been certified by the APSC to serve the Company's retail customers
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report
for seven years. The other half of the capacity will be sold into the wholesale market and will not affect retail rates.
Southern Company is aggressively working to maintain and expand its share of wholesale sales in the southeastern power markets. In January 2001, Southern Company announced the formation of a new subsidiary--Southern Power Company (SPC). The new subsidiary will own, manage, and finance wholesale generating assets in the Southeast. SPC will be the primary growth engine for Southern Company's market-based energy business. Energy from its assets will be marketed to wholesale customers under the Southern Company name.
Currently, the Company plans to transfer the generating facilities under construction in Autaugaville to SPC in 2001. The Company will enter into a purchased power agreement for half of the capacity of these generating facilities to serve its territorial customers.
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income of approximately $54 million in 2000. Pension plan income in 2001 is expected to be less as a result of plan amendments. Future pension income is dependent on several factors including trust earnings and changes to the plan. For more information, see Note 2.
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. There is a moratorium on any periodic retail rate increases (but not decreases) until July 2001.
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 1997, the APSC issued an additional order authorizing the Company to reduce balance sheet asset items. This order authorizes the reduction of such items up to an amount equal to five times the total estimated annual revenue reduction resulting from future rate reductions initiated by the Company.
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 Company's wholesale generating facilities under construction in Autaugaville, Alabama, all of which will be delivered 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 in 2003 while the remaining half is scheduled for delivery in 2004.
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 later under "Environmental Matters."
The staff of the Securities and Exchange Commission (SEC) has questioned certain of the current accounting practices of the electric utility industry -- including the Company -- regarding the recognition, measurement, and classification in the financial statements of decommissioning costs for nuclear generating facilities. In response to these questions, the FASB is reviewing the accounting for liabilities related to the retirement of long-lived assets, including nuclear decommissioning. If the FASB issues new accounting rules, the estimated costs of retiring the Company's nuclear and other facilities may be required to be recorded as liabilities in the Balance Sheets. Also, the annual provisions for such costs could change. Because of the Company's current ability to recover asset retirement costs through rates, these changes would not have a significant adverse effect on results of operations. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report
"Regulatory Assets and Liabilities" for additional information.
New Accounting Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. Statement No. 133 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 Company utilizes financial instruments to reduce its exposure to changes in foreign currency exchange rates. The Company also enters into commodity related forward 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 meet the definition of a derivative under Statement No. 133. In many cases, these transactions meet the normal purchase and sale exception and the related contracts will continue to be accounted for under the accrual method. Certain of these instruments qualify as cash flow hedges resulting in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness will be recognized currently in net income. However, others will be required to be marked to market through current period income.
The Company adopted Statement No. 133 effective January 1, 2001, with no material impact. The application of the new rules is still evolving and further guidance from FASB is expected, which could additionally impact the Company's financial statements.
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, 2000, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows. Also, based on the Company's overall interest rate exposure at December 31, 2000, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
FINANCIAL CONDITION
Overview
The Company's financial condition remained stable in 2000. This stability is the continuation over recent years of growth in retail energy sales and cost control measures combined with a 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 $871 million in 2000. 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.
Capital Structure
The Company's ratio of common equity to total capitalization -- including short-term debt -- was 42.2 percent in 2000 and 42.4 percent in 1999 and 1998.
During 2000, the Company issued $250 million of senior notes, the proceeds of which were used primarily to repay short-term indebtedness.
Capital Requirements
Capital expenditures are estimated to be $735 million for 2001, $891 million for 2002, and $625 million for 2003. 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,
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report
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 stock and replace these obligations with lower-cost capital if market conditions permit.
Environmental Matters
In November 1990, the Clean Air Act Amendments (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 integrated Southeast utility subsidiaries of Southern Company, including 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 and some 50 generating plants within the operating companies of Southern Company were brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Phase I 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 total construction expenditures through 2000 by $63 million
The one-hour ozone non-attainment standards for the Birmingham area have been set and must be implemented in May 2003. Two generating plants will be affected in the Birmingham area. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $230 million.
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 recently dismissed certain challenges but 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 will address other legal challenges to these standards in mid-2001. If the standards are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May 31, 2004. The final rule affects 21 states including Alabama. If standards and rules for implementation are upheld, the additional construction expenditures for compliance are estimated at approximately $189 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. 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 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 a notice of violation to the Company 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. On August 1, 2000, the U.S. District Court granted the Company's motion to dismiss for lack of jurisdiction in Georgia and granted the system service
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report
company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against the Company in federal district court in Birmingham, Alabama. The EPA did not include the system service company in the new complaint. The Company believes that it complied with applicable laws and EPA 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 December 2000, the EPA completed its utility studies 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 (MACT) provisions of the Clean Air Act. This determination is being challenged in the courts. 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 would likely be required around 2010. Litigation of the BART rules is probable in the near future.
Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C. add to the uncertainties associated with BART guidance and the MACT determination for mercury and other HAPS.
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; 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 costs and will recognize in the financial statements costs to clean up known sites. The Company has not incurred any 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, 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
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report
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," "expects," "plans," "anticipates," "believes," "estimates," "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 against the Company; the extent and timing of the entry of additional competition in the markets of the Company; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; internal restructuring or other restructuring options, that may be pursued by the Company; state and federal rate regulation in the United States; political, legal and economic conditions and developments in the United States; financial market conditions and the results of financing efforts; the impact of fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
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NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2000 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 integrated Southeast utilities, a system service company (SCS), Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern Nuclear), Mirant Corporation--formerly Southern Energy, Inc.-- and other direct and indirect subsidiaries. The integrated Southeast utilities --Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company-- provide electric service in four states. Contracts among the integrated Southeast utilities - 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). SCS provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Mirant acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Mirant businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
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.
Related-Party 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 transactions. Costs for these services amounted to $187 million, $218 million, and $201 million during 2000, 1999, and 1998, 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 $148 million, $135 million, and $137 million during 2000, 1999, and 1998, 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 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.
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Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following:
2000 1999 ----------------------- (in millions) Deferred income tax charges $ 346 $ 330 Deferred income tax credits (222) (265) Premium on reacquired debt 76 84 Department of Energy assessments 25 28 Vacation pay 32 30 Natural disaster reserve (18) (19) Other, net 30 59 - ---------------------------------------------------------------- Total $ 269 $ 247 ================================================================
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. Higher natural gas prices and decreased hydro production combined with increased costs of purchased power have resulted in a large under-recovery of fuel costs at December 31, 2000. Effective January 2001, the Company's fuel rate was increased to address this under-recovery. The Company expects to significantly reduce this balance over a three-year period.
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 $61 million in 2000, $63 million in 1999, and $59 million in 1998.
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 $25 million at December 31, 2000. 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 2000, 1999 and 1998. 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.
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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. 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 2000 and fund balances as of December 31, 2000 were:
(in millions) Amount expensed in 2000 $ 18 ----------------------------------------------------------
Accumulated provisions: External trust funds, at fair value $314 Internal reserves 38 ---------------------------------------------------------- Total $352 ==========================================================
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 $43 million in 2000, $23 million in 1999, and $9 million in 1998. The composite rate used to determine the amount of allowance was 9.6 percent in 2000, 8.8 percent in 1999, and 9.0 percent in 1998. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 8.4 percent in 2000, 4.7 percent in 1999, and 1.8 percent in 1998.
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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
The Company uses derivative financial instruments to hedge exposures to fluctuations in 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 is unaware of any counterparties that will fail to meet their obligations.
The 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 notional amount is 16 million euros maturing in 2001 through 2002. At December 31, 2000, the unrecognized gain on these swaps was approximately $1 million.
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, 2000 $3,422 $3,375 At December 31, 1999 3,286 3,045 Preferred Securities: At December 31, 2000 347 344 At December 31, 1999 347 299 --------------------------------------------------------------
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, 2000, the reserve balance was $18 million.
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 employees may become eligible for such benefits when they retire. The Company funds trusts to the
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extent deductible under federal income tax regulations or to the extent required by the APSC and 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. The effects of these changes will be to increase annual pension and postretirement benefits cost by approximately $8 million and $12 million, respectively.
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:
2000 1999 - ------------------------------------------------------------ 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 --------------------------- 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $873 $868 Service cost 22 23 Interest cost 64 57 Benefits paid (51) (51) Actuarial gain and employee transfers (8) (24) - --------------------------------------------------------------- Balance at end of year $900 $873 ===============================================================
Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $1,647 $1,461 Actual return on plan assets 302 245 Benefits paid (51) (51) Employee transfers 23 (8) - --------------------------------------------------------------- Balance at end of year $1,921 $1,647 ===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in millions) Funded status $1,021 $ 774 Unrecognized transition obligation (21) (25) Unrecognized prior service cost 33 36 Unrecognized net actuarial gain (765) (571) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 268 $ 214 ===============================================================
Components of the pension plans' net periodic cost were as follows:
2000 1999 1998 - ------------------------------------------------------------------ (in millions) Service cost $ 23 $ 23 $ 22 Interest cost 64 57 59 Expected return on plan assets (119) (109) (102) Recognized net actuarial gain (20) (14) (16) Net amortization (2) (2) (2) - ------------------------------------------------------------------ Net pension income $(54) $ (45) $(39) ==================================================================
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 --------------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $264 $278 Service cost 4 5 Interest cost 19 18 Benefits paid (12) (10) Actuarial gain and employee transfers (11) (27) - --------------------------------------------------------------- Balance at end of year $264 $264 ===============================================================
Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $161 $137 Actual return on plan assets 25 18 Employer contributions 18 16 Benefits paid (12) (10) - --------------------------------------------------------------- Balance at end of year $192 $161 ===============================================================
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The accrued postretirement costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in millions) Funded status $(72) $(103) Unrecognized transition obligation 49 53 Unrecognized net actuarial gain (35) (12) Fourth quarter contributions 4 8 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(54) $ (54) ===============================================================
Components of the plans' net periodic cost were as follows:
2000 1999 1998 - --------------------------------------------------------------- (in millions) Service cost $ 4 $ 5 $ 5 Interest cost 19 18 18 Expected return on plan assets (13) (11) (9) Net amortization 4 4 4 - --------------------------------------------------------------- Net postretirement cost $ 14 $ 16 $18 ===============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 7.29 percent for 2000, decreasing gradually to 5.50 percent through the year 2005, 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, 2000 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $15 $14 Service and interest costs 1 1 ===============================================================
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 2000, 1999, and 1998 were $11 million, $10 million, and $10 million, respectively.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs totaling $2.6 million, $5.6 million and $19.4 million for the years 2000, 1999 and 1998, respectively. These costs were deferred and are being amortized in accordance with regulatory treatment. The unamortized balance of these costs was $1.4 million at December 31, 2000.
3. CONTINGENCIES AND REGULATORY MATTERS
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action against the Company in the U. S. District Court. The complaint alleges violations of the prevention of significant deterioration and new source review provision 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 and granted SCS's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against the Company in federal district court in Birmingham, Alabama. The EPA did not include SCS in the new complaint. The Company believes that it complied with applicable laws and the EPA's
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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. Both increases and decreases have been placed into effect since the adoption of these rates. 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. There is a moratorium on any periodic retail rate increases (but not decreases) until July 2001.
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 1997, the APSC issued an additional order authorizing the Company to reduce balance sheet asset items. This order authorizes the reduction of such items up to an amount equal to five times the total estimated annual revenue reduction resulting from future rate reductions initiated by the Company. In 1998, the Company - in accordance with the 1995 rate order - recorded $33 million of additional amortization of premium on reacquired debt. The Company did not record any additional amounts in 2000 or 1999.
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 Company's wholesale generating facilities under construction in Autaugaville, Alabama, all of which will be delivered 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 in 2003 while the remaining half is scheduled for delivery in 2004.
The Company's ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
4. FINANCING AND COMMITMENTS
Construction Program
To the extent possible, the Company's construction program is expected to be financed primarily from internal sources. Short-term debt is often utilized and the amounts available are discussed below. The Company may issue additional long-term debt and preferred securities for debt maturities, redeeming higher-cost securities, and meeting additional capital requirements.
The Company currently estimates property additions to be $735 million in 2001, $891 million in 2002, and $625 million in 2003.
The Company is constructing 1,230 megawatts of wholesale generating facilities in Autaugaville, Alabama to begin operation in 2003. Half of this capacity has been certified by the APSC to serve the Company's retail customers for seven years. The other half of the capacity will be sold into the wholesale market and will not affect retail rates. During 2001, the Company plans to transfer these generating facilities to Southern Power Company (SPC), the new wholesale subsidiary formed by Southern Company. If the Company transfers wholesale generation assets to SPC as planned, construction expenditures for the years 2001 through 2003 will be $598 million, $591 million and $583 million, respectively.
During 2001, the Company expects to complete the replacement of the steam generators at Plant Farley, as well as the construction of new generating capacity at Plant Barry. In addition, 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 capital budget is subject to periodic review and revision, and actual capital costs incurred may vary from estimates because of changes in such factors as: business conditions; environmental regulations; nuclear plant
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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.
Financing
The ability of the Company to finance its capital budget depends on the amount of funds generated internally and the funds it can raise by external financing. 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.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $925 million (including $418 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds). Of these lines, $535 million expire at various times during 2001 and $390 million expire in 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.
At December 31, 2000, the Company had regulatory approval to have outstanding up to $750 million 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.
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, 2000 were as follows:
Year Commitments - ---- --------------- (in millions) 2001 $ - 2002 - 2003 16 2004 34 2005 37 2006 and beyond 180 - ----------------------------------------------------------- Total commitments $ 267 ===========================================================
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, 2000, were as follows:
Year Commitments - ---- --------------- (in millions) 2001 $ 998 2002 841 2003 722 2004 669 2005 525 2006 - 2024 2,287 - ----------------------------------------------------------- Total commitments $6,042 ===========================================================
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Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $20.9 million in 2000, $17.8 million in 1999, and $5.8 million in 1998. At December 31, 2000, estimated minimum rental commitments for noncancellable operating leases were as follows:
Year Commitments - ---- ------------- (in millions) 2001 $ 22.2 2002 21.6 2003 21.2 2004 18.2 2005 15.5 2006 - 2017 44.7 - ----------------------------------------------------------- Total minimum payments $143.4 ===========================================================
5. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power Company 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 transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power Company 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 $85 million in 2000, $92 million in 1999 and $74 million in 1998, 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 Company 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, 2000, the capitalization of SEGCO consisted of $51 million of equity and $78 million of long-term debt on which the annual interest requirement is $5.3 million. SEGCO paid dividends totaling $5.1 million in 2000, $4.3 million in 1999, and $8.7 million in 1998, of which one-half of each was paid to the Company. SEGCO's net income was $5.9 million, $5.4 million, and $7.5 million for 2000, 1999 and 1998, respectively.
The Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2000, 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 $100 $ 46 Plant Miller Units 1 and 2 743 312 ----------------------------------------------------------
6. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the other integrated utility subsidiaries of Southern Company have entered into 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 -- expiring at various dates discussed below -- 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 Company's capacity revenues amounted to $127 million in 2000, $122 million in 1999, and $142 million in 1998.
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 1,235 megawatts of capacity are II-70
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scheduled to be sold through 2001. Thereafter, these sales will remain at that approximate level -- 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. No notices of cancellation have been received.
Alabama Municipal Electric Authority (AMEA) Capacity Contracts
In August 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 commencing September 1, 1986 (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 commencing October 1, 1991 (1991 Contract). In both contracts the power will be sold to AMEA for its member municipalities that previously were served directly by the Company as wholesale customers. 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. These payments are being recognized as operating revenues and the discounts are being amortized to other interest expense as scheduled capacity is made available over the terms of the contracts.
In order 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 occurs. As the liquidated damages decline under the contracts, a portion of the bonds equal to the decreases is returned to the Company. At December 31, 2000, $61.3 million of such bonds were held by the escrow agent under the contracts.
7. INCOME TAXES
At December 31, 2000, the tax-related regulatory assets and liabilities were $346 million and $222 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:
2000 1999 1998 -------------------------------- (in millions) Total provision for income taxes: Federal -- Current $168 $194 $123 Deferred 60 24 72 - ----------------------------------------------------------------- 228 218 195 - ----------------------------------------------------------------- State -- Current 27 19 16 Deferred 7 5 7 - ------------------------------------------------------ ---------- 34 24 23 - ----------------------------------------------------------------- Total $262 $242 $218 =================================================================
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:
2000 1999 ------------------ (in millions) Deferred tax liabilities: Accelerated depreciation $ 992 $884 Property basis differences 405 419 Fuel cost adjustment 93 65 Premium on reacquired debt 30 31 Pensions 75 60 Other 12 11 - ----------------------------------------------------------------- Total 1,607 1,470 - ----------------------------------------------------------------- Deferred tax assets: Capacity prepayments 18 24 Other deferred costs 14 25 Postretirement benefits 24 22 Unbilled revenue 23 13 Other 81 63 - ----------------------------------------------------------------- Total 160 147 - ----------------------------------------------------------------- Net deferred tax liabilities 1,447 1,323 Portion included in current liabilities, net (46) (83) - ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,401 $1,240 =================================================================
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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 2000, 1999, and 1998. At December 31, 2000, 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:
2000 1999 1998 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.1 2.4 2.5 Non-deductible book depreciation 1.4 1.6 1.5 Differences in prior years' deferred and current tax rates (1.3) (1.3) (1.6) Other (0.7) (0.9) (1.6) - --------------------------------------------------------------- Effective income tax rate 37.5% 36.8% 35.8% ===============================================================
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.
8. COMPANY OBLIGATED 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 6.52% at January 1, 2001.
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.
9. OTHER LONG-TERM DEBT
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 May 2000, the Company issued $250 million of unsecured senior notes. The proceeds of this issuance were used to repay short-term indebtedness. All of the Company's senior notes are, in effect, subordinated to all secured debt of the Company, including its first mortgage bonds.
The estimated aggregate annual maturities of capitalized lease obligations through 2005 are as follows: $0.8 million in 2001, $0.9 million in 2002, $0.9 million in 2003, $1.0 million in 2004 and $0.1 million in 2005.
10. 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:
2000 1999 ------------------------ (in thousands) First mortgage bond maturities and redemptions $ - $100,000 Other long-term debt maturities (Note 9) 844 943 ------------------------------------------------------------- Total long-term debt due within one year $844 $100,943 =============================================================
The annual first mortgage bond improvement fund requirement is 1 percent of the aggregate principal amount of bonds of each series authenticated, so long
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NOTES (continued) Alabama Power Company 2000 Annual Report
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.
11. 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 private insurance, 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 be insured against increased costs of replacement power in an amount up to $3.5 million per week (starting 12 weeks after the outage) for one year and up to $2.8 million per week for the second and third 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 $17 million.
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.
12. COMMON STOCK 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, 2000, retained earnings of $796 million were restricted against the payment of cash dividends on common stock under terms of the mortgage indenture.
13. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 2000 and 1999 are as follows:
Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock - -------------------- ----------------------------------------- (in millions)
March 2000 $ 746 $172 $ 68 June 2000 900 229 103 September 2000 1,137 390 209 December 2000 884 151 40
March 1999 $ 714 $162 $ 63 June 1999 823 209 93 September 1999 1,116 388 201 December 1999 733 136 43 - -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
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GEORGIA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Georgia Power Company 2000 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 Thomas A. Fanning Executive Vice President, Treasurer and Chief Financial Officer
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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, 2000 and 1999, 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, 2000. 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-88 through II-108) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP Atlanta, Georgia February 28, 2001
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 2000 earnings totaled $559 million, representing an $18 million (3.3 percent) increase over 1999. This earnings increase is 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. Georgia Power Company's 1999 earnings totaled $541 million, representing a $29 million (5.1 percent) decrease from 1998. This earnings decrease was primarily due to the recognition of interest income in 1998 as a result of the resolution of tax issues with the Internal Revenue Service (IRS). Earnings in 1999 from normal operations increased due primarily to lower accelerated depreciation under the GPSC retail rate order, sales growth, and decreased financing costs, partially offset by retail rate reductions under the new order and lower wholesale revenues.
Revenues
Operating revenues in 2000 and the amount of change from the prior year are as follows:
Increase (Decrease) From Prior Year Amount ---------------------- 2000 2000 1999 ---- ----------------------- Retail - (in millions) Base revenues $3,119 $ 84 $(292) Fuel cost recovery 1,198 183 44 - --------------------------------------------------------------------- Total retail 4,317 267 (248) - --------------------------------------------------------------------- Sales for resale - Non-affiliates 298 88 (49) Affiliates 96 20 (5) - --------------------------------------------------------------------- Total sales for resale 394 108 (54) - --------------------------------------------------------------------- Other operating revenues 160 39 21 - -------------------------------------------------------- ------------ Total operating revenues $4,871 $414 $(281) ===================================================================== Percent change 9.3% (5.9)% - ---------------------------------------------------------------------
Retail base revenues of $3.1 billion in 2000 increased $84 million (2.8 percent) primarily due to a 4.9 percent increase in sales. Under the 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. Refunds will be made to customers in 2001. Retail base revenues of $3.0 billion in 1999 decreased $292 million (8.8 percent) primarily due to retail rate reductions under the GPSC retail rate order. Pursuant to the GPSC retail rate order, in 1999 the Company also recorded $79 million of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity. Revenue subject to refund is reflected in "Base revenues" in the chart above. The $79 million in refunds were made to customers in 2000. See Note 3 to the financial statements under "Retail Rate Order" 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, 2000, the Company had $132 million in underrecovered fuel costs. The Company currently plans to make a filing with the GPSC in early 2001 to establish a new fuel rate in order to better reflect current fuel cost and to collect the current underrecovered balance.
Wholesale revenues from sales to non-affiliated utilities increased in 2000 and decreased in 1999 as follows:
2000 1999 1998 ------------------------------- (in millions) Outside service area - Long-term contracts $ 55 $ 55 $ 51 Other sales 162 74 93 Inside service area 81 81 115 - --------------------------------------------------------------- Total $298 $210 $259 ===============================================================
Revenues from long-term contracts outside the service area remained constant in 2000 and increased slightly in 1999 due to increased energy sales. See Note 7 to the financial statements for further information regarding these sales. Revenues from other sales outside the service area primarily represent wholesale sales from Plant Dahlberg which went into service during 2000 and increases in power marketing activities. These activities include the purchase and resale of energy. Consequently, changes in revenues are generally offset by corresponding changes in purchased power expense from non-affiliates. Wholesale
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
revenues from customers within the service area remained constant in 2000 but decreased in 1999 primarily due to a decrease in revenues under a power supply agreement with Oglethorpe Power Corporation (OPC).
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 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. In 1999, other operating revenues increased $21 million or (21 percent) from the previous year due primarily to increased revenues from the rental of electric equipment and property.
Kilowatt-hour (KWH) sales for 2000 and the percent change by year were as follows:
Percent Change ---------------------- KWH 2000 1999 --------- ------------------------ (in billions) Residential 20.7 6.6% (0.4)% Commercial 25.6 8.1 3.7 Industrial 27.5 0.9 0.1 Other 0.6 3.2 1.5 --------- Total retail 74.4 4.9 1.1 --------- Sales for resale - Non-affiliates 6.5 27.7 (21.4) Affiliates 2.4 35.6 (11.9) --------- Total sales for resale 8.9 29.8 (19.1) --------- Total sales 83.3 7.1 (1.0) =========
- ------------------------------------------------------------
Residential and commercial sales increased 6.6 percent and 8.1 percent, respectively, 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. In 1999, residential sales decreased 0.4 percent due to moderate summer temperatures, while commercial sales increased 3.7 percent due to strong regional economic growth. 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:
2000 1999 1998 ----------------------------- Total generation (billions of KWH) 73.6 69.3 69.1 Sources of generation (percent) -- Coal 75.8 75.5 73.3 Nuclear 21.2 21.6 21.6 Hydro 0.8 1.0 2.6 Oil and gas 2.2 1.9 2.5 Average cost of fuel per net KWH generated (cents) -- 1.39 1.34 1.36 - -----------------------------------------------------------------
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. Fuel expense increased 0.3 percent in 1999 due to a slight increase in fossil and nuclear generation and a decrease in generation from hydro plants, partially offset by a lower average cost of fuel.
Purchased power expense in 2000 increased $206 million (53 percent) over the prior year due to higher retail energy demands and power marketing activities. The majority of the increase was offset by increases in retail fuel revenues and power marketing revenues and therefore did not affect earnings. As discussed above, the expense associated with energy purchased for power marketing activities is generally offset by revenue when resold. Purchased power expense decreased slightly in 1999.
Other operation and maintenance expenses in 2000 increased slightly over those in 1999. Increased line maintenance, customer assistance and sales expense and additional severance costs were partially offset by decreased generating plant maintenance and decreased employee benefit provisions. Other operation and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
maintenance expenses increased 1.6 percent in 1999 primarily due to increased generating plant maintenance, partially offset by a reduction in the charges related to the implementation of a customer service system in 1998, decreased year 2000 readiness costs, and decreased employee benefit provisions.
Depreciation and amortization increased $66 million in 2000 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. Depreciation and amortization decreased $261 million in 1999 primarily due to higher depreciation charges recognized in 1998 under the prior GPSC accounting order and the completion in 1998 of the amortization of deferred Plant Vogtle costs.
Interest income decreased $3 million in 2000 primarily due to decreased interest on temporary cash investments. Interest income decreased in 1999 primarily due to the 1998 recognition of $73 million in interest income resulting from the resolution of tax issues with the IRS and the State of Georgia. Other, net decreased in 2000 due to an increase in charitable contributions. In 1999, other, net decreased due primarily to increased bad debt expense related to consumer energy efficiency improvement financing.
Interest expense, net increased in 2000 due to the issuance of an additional $300 million in senior notes during 2000. Interest expense, net decreased in 1999 due primarily to the refinancing or retirement of securities. The Company refinanced or retired $179 million and $775 million of securities in 2000 and 1999, respectively. Distributions on preferred securities of subsidiary companies decreased $7 million in 2000 due to the redemption of $100 million of preferred securities in December 1999. Distributions on preferred securities of subsidiary companies increased $11 million in 1999 due to the issuance of additional mandatorily redeemable preferred securities in January 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 life. 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
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.
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 January 1, 1999, the Company began operating under a new three-year retail rate order. The Company's earnings are evaluated against a retail return on common equity range of 10 percent to 12.5 percent, with required rate reductions of $262 million on an annual basis effective in 1999 and an additional $24 million effective in 2000. The order provides 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 will be applied to rate reductions, with the remaining one-third retained by the Company. Pursuant to the GPSC retail rate order, in 2000 and 1999, the Company recorded $85 million in accelerated amortization of regulatory assets. In 2000, the Company also recorded the additional $50 million of accelerated amortization. The accelerated amortization is recorded in a regulatory liability account as mandated by the GPSC. In addition, the Company recorded $44 million and $79 million of revenue subject to refund for estimated earnings above 12.5 percent in 2000 and 1999, respectively. Refunds applicable to 1999 were made to customers in 2000. The Company will file a general rate case on July 2, 2001 in response to which the GPSC would be expected to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
determine whether the retail rate order should be continued, modified, or discontinued. See Note 3 to the financial statements under "Retail Rate Order" for additional information.
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. Assuming normal weather, retail sales growth from 2000 is projected to be approximately 2.4 percent annually on average during 2001 through 2003.
The Company has entered into purchase power agreements which will result in higher capacity and operating and maintenance payments in future years. See Note 4 to the financial statements under "Purchased Power Commitments" for additional information.
The Company is constructing two 566 megawatt combined cycle units at Plant Wansley to begin operation in 2002. These units have been certified by the GPSC to serve the Company's retail customers for approximately seven years. Savannah Electric will have the rights to 200 megawatts of capacity from these units for the same seven-year period.
The Company is also constructing a 571 megawatt combined cycle unit at Plant Goat Rock to begin operation in 2002, and a 610 megawatt combined cycle unit at Plant Goat Rock to begin operation in 2003. The power from these units will initially be sold into the wholesale market when they begin operation. The Company has filed with the GPSC for certification of these units to begin serving the Company's retail customers in 2003 and 2004, respectively, for a term of seven years each.
In addition to seeking certification of Plant Goat Rock, the Company is also seeking certification of a seven year commitment to 615 megawatts beginning in 2004 at Plant Autaugaville to serve its retail customers. Plant Autaugaville is currently under construction by Alabama Power.
Further, the Company is constructing Plant Dahlberg, a ten unit, 800 megawatt combustion turbine peaking power plant that will serve the wholesale market. Units one through eight began operation in May 2000; units nine and ten are expected to begin operation in June 2001. The Company has entered into wholesale contracts to sell all 800 megawatts of capacity. These contracts cover substantially all of the output of the plant for the first five years. Because these units are dedicated to the wholesale market, retail rates will not be affected.
The Company is aggressively working to maintain and expand its share of wholesale sales in the Southeastern power markets. In January 2001, Southern Company announced the formation of a new subsidiary, Southern Power Company (SPC). SPC will own, manage, and finance wholesale generating assets in the Southeast. Energy from its assets will be marketed to wholesale customers under the Southern Company name. The current plan is for Georgia Power and Alabama Power to transfer Plant Dahlberg and the units under construction at Plants Wansley, Goat Rock, and Autaugaville to SPC in 2001. The Company will enter into purchased power capacity agreements with SPC for power from the units at Plants Wansley, Goat Rock, and Autaugaville to serve the Company's retail customers.
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income of approximately $59 million in 2000. Pension plan income in 2001 is expected to be less as a result of plan amendments. Future pension income is dependent on several factors including trust earnings and changes to the plan. For additional information see Note 2 to the financial statements.
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.
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. Although the Energy Act
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry.
On December 20, 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. After participating in regional conferences with customers and other members of the public to discuss the formation of RTOs, utilities were required to make a filing with the FERC. On October 16, 2000, Southern Company and its five integrated Southeast utilities, including the Company, filed with the FERC a proposal for the creation of an RTO. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of participating utilities. Participants would have the option to either maintain their ownership, divest, sell, or lease their assets to the proposed RTO. If the FERC accepts the proposal as filed, the creation of the RTO is not expected to have a material impact on the financial statements of the Company. However, the ultimate outcome of this matter cannot now be determined.
The Company continues to 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. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition across the nation. 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. 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 transmission pricing and recovery of costs. The GPSC continues its assessment of the range of potential stranded costs. The inability of the Company to recover all its costs, including the regulatory assets described in Note 1 to the financial statements, could have a material effect on the financial condition of the Company. The Company is attempting to reduce regulatory assets through the GPSC retail rate order. See Note 3 to the financial statements under "Retail Rate Order" for additional information.
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.
The staff of the Securities and Exchange Commission (SEC) has questioned certain of the current accounting practices of the electric utility industry - including the Company's - regarding the recognition, measurement, and classification in the financial statements of decommissioning costs for nuclear generating facilities. In response to these questions, the FASB is reviewing the accounting for liabilities related to the retirement of long-lived assets, including nuclear decommissioning. If the FASB issues new accounting rules, the estimated costs of retiring the Company's nuclear and other facilities may be required to be recorded as liabilities in the Balance Sheets. Also, the annual provisions for such costs could change. Because of the Company's current ability to recover asset retirement costs through rates, these changes would not have a significant adverse effect on results of operations. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information.
Exposure to Market Risks
Due to cost-based rate regulation, the Company currently has limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. (See the discussion above for potential changes in industry structure.) 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, 2000, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows. Also, based on the Company's overall interest rate exposure at December 31, 2000, a near-term 100 basis point
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
change in interest rates would not materially affect the financial statements.
New Accounting Standard
In June 2000, the FASB issued Statement No. 138, an amendment of Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. Statement No. 133 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.
Substantially all of the Company's bulk energy purchases and sales meet the definition of a derivative under Statement No. 133. In many cases, these transactions meet the normal purchase and sale exception and the related contracts will continue to be accounted for under the accrual method. Certain of these instruments qualify as cash flow hedges resulting in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness will be recognized currently in net income. However, others will be required to be marked to market through current period income.
The Company adopted the provisions of Statement No. 133 effective January 1, 2001. The impact on net income was immaterial. The application of the new rules is still evolving and further guidance from the FASB is expected, which could additionally impact the Company's financial statements.
FINANCIAL CONDITION
Plant Additions
In 2000, gross utility plant additions were $1.1 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.
Financing Activities
In 2000, the Company's financing costs increased due to the issuance of new debt during the year. New issues during 1998 through 2000 totaled $1.5 billion and retirement or repayment of higher-cost securities totaled $1.7 billion.
Special purpose subsidiaries of the Company have issued mandatorily redeemable preferred securities. See Note 9 to the financial statements under "Preferred Securities" for additional information.
Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 1998 through 2000, as of year-end, were as follows:
2000 1999 1998 ---------------------------------- Composite interest rate on long-term debt 5.90% 5.48% 5.64% Composite preferred stock dividend rate 4.60 4.60 5.52 Composite preferred securities dividend rate 7.49 7.49 7.89 - ------------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations decreased by $135 million in 2000, primarily due to higher fuel and purchased power expenses related to increased energy demands.
The Company estimates that construction expenditures for the years 2001 through 2003 will total $1.6 billion, $1.3 billion, and $0.8 billion, respectively. If the Company transfers wholesale generation assets to SPC in 2001 as contemplated, construction expenditures for the years 2001 through 2003 will total $1.0 billion, $0.9 billion, and $0.7 billion, respectively. Investments in additional combustion turbine and combined cycle generating units, transmission and distribution facilities, enhancements to existing generating plants, and equipment to comply with environmental requirements are planned.
Cash requirements for redemptions announced and maturities of long-term debt are expected to total $581 million during 2001 through 2003.
As a result of requirements by the Nuclear Regulatory Commission, the Company has established external trust funds for the purpose of funding nuclear
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
decommissioning costs. The amount to be funded is $30 million each year in 2001, 2002, and 2003. 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, if needed, by the issuance of new debt and equity securities, term loans, and short-term borrowings. 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 2001. See Note 9 to the financial statements under "Bank Credit Arrangements" for additional information.
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 the later securities has been steadily declining during the last four years.
If the Company were to choose to issue new first mortgage bonds or preferred stock once again, it would be required to meet certain coverage requirements.
ENVIRONMENTAL ISSUES
Clean Air Act
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. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants are required in two phases. Phase I compliance began in 1995 and some 50 generating units within Southern Company's subsidiaries were brought into compliance with Phase I requirements.
Southern Company's subsidiaries, including the Company, achieved Phase I sulfur dioxide compliance at the affected units by switching to low-sulfur coal, which required 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.
The one-hour ozone non-attainment standards for the Atlanta area have been set and must be implemented in May 2003. Seven generating plants will be affected in the Atlanta area. Additional construction expenditures for the Company's compliance with these new rules are currently estimated at approximately $705 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
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 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 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 unless such costs can be recovered through regulated rates.
Other Environmental Issues
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 recently dismissed certain challenges but 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 will address other legal challenges to these standards in mid-2001. If the standards are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May 31, 2004. The final rule affects 21 states, including Georgia.
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 (MACT) provisions of the Clean Air Act. This determination is being challenged in the courts. 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 would likely be required around 2010. Litigation of the BART rules is probable in the near future.
Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C. add to the uncertainties associated with BART guidance and the MACT determination for mercury and other HAPS.
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 costs and has recognized in the financial statements costs to clean up known sites. These costs for the Company amounted to $4 million, $4 million, and $6 million in 2000, 1999, and 1998, respectively. Additional sites may require environmental remediation for which the Company may be liable for a portion of or all 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 a site in Brunswick, Georgia, and the status of sites listed on the State of Georgia's hazardous site inventory.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2000 Annual Report
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; water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations.
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.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
The Company's 2000 Annual Report contains forward-looking and historical information. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "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 and the race discrimination litigation against the Company; the extent and timing of the entry of additional competition in the Company's markets; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; internal restructuring or other restructuring options, that may be pursued by the Company; state and federal rate regulation in the United States; political, legal and economic conditions and developments in the United States; financial market conditions and the results of financing efforts; the impact of fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
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NOTES TO FINANCIAL STATEMENTS Georgia Power Company 2000 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 integrated Southeast utilities, Southern Company Services (SCS), the system service company, Southern Communications Services (Southern LINC), Mirant Corporation (formerly Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The integrated Southeast utilities (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four states. Contracts among the integrated Southeast utilities -- related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC). SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the subsidiary companies and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Mirant Corporation acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Mirant Corporation's businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the Southeastern United States.
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.
Related-Party 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 $269 million, $253 million, and $251 million during 2000, 1999, and 1998, 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, $270 million, and $269 million during 2000, 1999, and 1998, 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 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. Pursuant to the terms of the GPSC retail rate order, the Company recorded $135 million and $85 million in 2000 and 1999, respectively, of accelerated cost recovery of regulatory assets which have
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NOTES (continued) Georgia Power Company 2000 Annual Report
been recorded on the balance sheet as a regulatory liability. See Note 3 under "Retail Rate Order" for additional information. Regulatory assets and (liabilities) reflected in the Company's Balance Sheets at December 31 relate to the following:
2000 1999 ---------------------- (in millions) Deferred income taxes $ 566 $ 591 Deferred income tax credits (247) (267) Premium on reacquired debt 174 184 Corporate building lease 55 54 Vacation pay 49 47 Postretirement benefits 30 33 Department of Energy assessments 21 24 Deferred nuclear outage costs 28 26 Accelerated cost recovery (220) (85) Interest, accelerated cost recovery (10) - Other, net 23 3 - --------------------------------------------------------------- Total $ 469 $ 610 ===============================================================
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.
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.
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.
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 2000, $74 million in 1999, and $74 million in 1998. 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 contracts, and the Company is pursuing legal remedies against the government for breach of contract. Effective June 2000, the on-site dry storage facility for Plant Hatch became operational. Sufficient capacity is believed available to continue dry storage operations at Plant Hatch through the life of the plant. Sufficient fuel storage capacity currently is available at Plant Vogtle to maintain full-core discharge capability for both units into the year 2014.
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, 2000 to be approximately $19 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 2000 and 1999, and 3.2 percent in 1998. In addition, pursuant to a GPSC retail rate order, the Company recorded accelerated depreciation of electric plant of $304 million in 1998. Total accelerated depreciation recorded under the GPSC retail rate order was $467 million. These charges are recorded in the accumulated provision for depreciation. When property subject to depreciation is retired or otherwise disposed of in the normal course of
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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 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 a set period of time as ordered by the GPSC. 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. The Company has filed with the NRC an application requesting a 20-year renewal of the licenses for both units at Plant Hatch which would permit the operation of both units until 2034.
Annual provisions for nuclear decommissioning expense are based on an annuity method as approved by the GPSC. The amounts expensed in 2000 and fund balances as of December 31, 2000 were:
Plant Plant Hatch Vogtle - ---------------------------------------------------------------- (in millions) Amount expensed in 2000 $ 19 $ 9 ================================================================ (in millions) Accumulated provisions: External trust funds, at fair value $230 $146 Internal reserves 20 12 - ---------------------------------------------------------------- Total $250 $158 ================================================================
Effective January 1, 1999, the GPSC increased the annual provision for decommissioning expenses to $28 million from $20 million in 1998. This amount is based on the NRC generic estimate to decommission the radioactive
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portion of the facilities as of 1997 of $526 million and $438 million for Plants Hatch and Vogtle, respectively. The ultimate costs associated with the 1997 NRC minimum funding requirements are $1.1 billion and $1.3 billion for Plants Hatch and Vogtle, respectively. Significant assumptions include an estimated inflation rate of 3.6 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.
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 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 2000, 1999, and 1998, the average AFUDC rates were 6.74 percent, 5.61 percent, and 6.71 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 2.0 percent for 2000, 1999 and 1998.
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.
Financial Instruments
The Company has a firm commitment that requires payment in euros. As a hedge against fluctuations in the exchange rate for euros, the Company entered into forward currency swaps. The notional amount is 15.9 million euros maturing in 2001 through 2002. At December 31, 2000, the unrecognized gain on these swaps was approximately $1.3 million.
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, 2000 $2,959 $2,912 At December 31, 1999 $2,758 $2,604 Preferred securities: At December 31, 2000 $789 $761 At December 31, 1999 $789 $680 - --------------------------------------------------------------
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 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 FERC. In late 2000, the Company adopted several pension and postretirement benefits plan changes that had the
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effect of increasing benefits to both current and future retirees. The effects of these changes will be to increase annual pension and postretirement benefits costs by approximately $10 million and $6 million, respectively. 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:
2000 1999 - ----------------------------------------------------------------- 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 --------------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $1,205 $1,217 Service cost 32 33 Interest cost 88 80 Benefits paid (58) (57) Actuarial gain and employee transfers (14) (68) - ---------------------------------------------------------------- Balance at end of year $1,253 $1,205 ================================================================
Plan Assets --------------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $2,107 $1,859 Actual return on plan assets 385 313 Benefits paid (58) (57) Employee transfers 30 (8) - ---------------------------------------------------------------- Balance at end of year $2,464 $2,107 ================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in millions) Funded status $ 1,211 $ 902 Unrecognized transition obligation (26) (30) Unrecognized prior service cost 38 41 Unrecognized net actuarial gain (1,018) (767) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 205 $ 146 ===============================================================
Components of the plan's net periodic cost were as follows:
2000 1999 1998 - --------------------------------------------------------------- (in millions) Service cost $ 32 $ 33 $ 30 Interest cost 88 80 82 Expected return on plan assets (151) (137) (127) Recognized net actuarial gain (27) (17) (20) Net amortization (1) (1) (1) - --------------------------------------------------------------- Net pension income $ (59) $ (42) $ (36) ===============================================================
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 --------------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $438 $464 Service cost 7 8 Interest cost 36 30 Benefits paid (21) (19) Actuarial gain and employee transfers (28) (45) Amendments 63 - - ---------------------------------------------------------------- Balance at end of year $495 $438 ================================================================
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Plan Assets --------------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $177 $150 Actual return on plan assets 12 11 Employer contributions 30 35 Benefits paid (21) (19) - ---------------------------------------------------------------- Balance at end of year $198 $177 ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in millions) Funded status $ (297) $ (261) Unrecognized transition obligation 113 122 Unrecognized prior service cost 60 - Unrecognized gain (13) - Unrecognized net actuarial loss - 10 Fourth quarter contributions 27 14 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (110) $(115) ===============================================================
Components of the plans' net periodic cost were as follows:
2000 1999 1998 - --------------------------------------------------------------- (in millions) Service cost $ 7 $ 8 $ 7 Interest cost 36 30 32 Expected return on plan assets (16) (10) (9) Recognized net actuarial loss - 1 1 Net amortization 12 9 9 - ------------------------------------------------------ -------- Net postretirement cost $ 39 $ 38 $40 ===============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 7.29 percent for 2000, decreasing gradually to 5.50 percent through the year 2005, 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, 2000 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $ 39 $ 34 Service and interest costs 3 3 ===============================================================
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 2000, 1999, and 1998 were $15 million, $15 million, and $14 million, respectively.
3. CONTINGENCIES & REGULATORY MATTERS
Retail Rate Order
On December 18, 1998, the GPSC approved a three-year retail rate order for the Company ending December 31, 2001. Under the terms of the order, earnings are evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Retail rates were decreased by $262 million on an annual basis effective January 1, 1999, and by an additional $24 million effective January 1, 2000. The order further provides 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 will be applied to rate reductions, with the remaining one-third retained by the Company. Pursuant to the order, in 2000 and 1999, the Company recorded $85 million each year in accelerated amortization of regulatory assets. In 2000, the Company also recorded the additional $50 million of accelerated amortization. The accelerated amortization is recorded in a regulatory liability account and, as mandated by the GPSC, the Company recorded $10 million of interest on the amounts in the regulatory liability account. In addition, the Company recorded $44 million and $79 million of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity in 2000 and 1999, respectively. Refunds applicable to 1999 were made to customers in 2000. The estimated 2000 refund is included in other current liabilities on the Balance Sheet. The Company will file a general rate case on July 2, 2001, in response to
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which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued.
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 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.
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.
Other Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by the EPA that they have been designated as potentially responsible parties under the Comprehensive Environmental Response, Compensation and Liability Act with respect to a site in Brunswick, Georgia. As of December 31, 2000, the Company has recognized approximately $5 million in cumulative expenses associated with the Company's agreed upon share of removal and remedial investigation and feasibility study costs for this site. The final outcome of this matter cannot now be determined. However, based on the nature and extent of the Company's activities relating to the site, management believes that the Company's portion of any remaining remediation costs should not be material to the financial statements.
In compliance with the Georgia Hazardous Site Response Act of 1993, the State of Georgia was required to compile an inventory of all known or suspected sites where hazardous wastes, constituents, or substances have been disposed of or released in quantities deemed reportable by the State. In developing this list, the State identified several hundred properties throughout the State, including 34 sites which may require environmental remediation that were either previously or are currently owned by the Company. The majority of these sites are electrical power substations and power generation facilities. The Company has remediated ten electrical substations on the list at a cumulative cost of approximately $3 million through December 31, 2000. The State has removed from the list three power generation facilities following the assessment which indicated no remediation was necessary. In addition, the Company has recognized approximately $27.5 million in cumulative expenses through December 31, 2000 for the assessment of the remaining sites on the list and the anticipated clean-up cost for 14 sites that the Company plans to remediate. Any additional costs of remediating the remaining sites cannot presently be determined until such studies are completed for each site and the State determines whether remediation is required. If all listed sites were required to be remediated, the Company could incur expenses of up to approximately $5 million in additional clean-up costs and construction expenditures of up to approximately $37 million to develop new waste management facilities or install additional pollution control devices.
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
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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.
In January 1997, the GPSC approved a performance award of approximately $11.7 million for performance during the 1993-1995 period. This award was collected through the retail fuel cost recovery provision and recognized in income over the 36-month period ending in December 1999. In February 2000, the GPSC approved a performance award of approximately $7.8 million for performance during the 1996-1998 period. This award is being collected through the retail fuel cost recovery provision and recognized in income over a 36-month period that began in January 2000, 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 and a new defendant, Southern Company Energy Solutions, Inc. The lawsuit is in the discovery stage. The final outcome of this case cannot now be determined.
4. COMMITMENTS
Construction Program
The Company is constructing Plant Dahlberg, a ten unit, 800 megawatt combustion turbine peaking power plant. Units one through eight began operation in May 2000; units nine and ten are expected to begin operation in June 2001. The Company is also constructing a 571 megawatt combined cycle unit and a 610 megawatt combined cycle unit at Plant Goat Rock that will begin operation in 2002 and in 2003, respectively, and an addition of two 566 megawatt combined cycle units at Plant Wansley, to begin operation in 2002. During 2001, the Company plans to transfer the units at Plants Dahlberg, Goat Rock, and Wansley at net book value to Southern Power Company (SPC), a new subsidiary formed by Southern Company. Significant construction of transmission and distribution facilities, and projects to upgrade and extend the useful life of generating plants and to remain in compliance with environmental requirements will continue. The Company currently estimates property additions to be approximately $1.6 billion in 2001, $1.3 billion in 2002, and $0.8 billion in 2003. If the Company transfers wholesale generation assets to SPC in 2001 as contemplated, construction expenditures for the years 2001 through 2003 will total $1.0 billion, $0.9 billion, and $0.7 billion, respectively.
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. Total estimated long-term fossil and nuclear fuel commitments at December 31, 2000 were as follows:
Minimum Year Obligations - ---- ----------------- (in millions) 2001 $1,006 2002 625 2003 586 2004 430 2005 342 2006 and beyond 873 - ------------------------------------------------------------- Total minimum obligations $3,862 =============================================================
Additional commitments for coal and for nuclear fuel will be required in the future to supply the Company's fuel needs.
Purchased Power Commitments
The Company and an affiliate, Alabama Power Company, own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which
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NOTES (continued) Georgia Power Company 2000 Annual Report
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 Company 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:
2000 1999 1998 --------------------------------- (in millions) Energy $57 $51 $45 Capacity 30 29 30 - -------------------------------------------------------------- Total $87 $80 $75 ============================================================== Kilowatt-hours 3,835 3,338 3,146 - --------------------------------------------------------------
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 $58 million, $57 million, and $56 million in 2000, 1999, and 1998, respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments ---------------------- (in millions) 2001 $ 59 2002 58 2003 58 2004 55 2005 55 2006 and beyond 539 - ---------------------------------------------------------------- Total capacity payments $ 824 ================================================================
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.
The Company has entered into other various long-term commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2000 were as follows:
Year Other Obligations ---------------------- (in millions) 2001 $ 22 2002 39 2003 41 2004 40 2005 40 2006 and beyond 154 - ---------------------------------------------------------------- Total other obligations $336 ================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $16 million for 2000, $11 million for 1999, and $13 million for 1998. At December 31, 2000, estimated minimum rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations -------------------------- (in millions) 2001 $ 15 2002 15 2003 15 2004 16 2005 14 2006 and beyond 102 - ----------------------------------------------------------------- Total minimum obligations $ 177 =================================================================
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 private insurance, with the remaining coverage provided by a mandatory program
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NOTES (continued) Georgia Power Company 2000 Annual Report
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 be insured against increased costs of replacement power in an amount up to $3.5 million per week -- starting 12 weeks after the outage -- for one year and up to $2.8 million per week for the second and third 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 $19 million.
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, 2000, 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% $3,301* $1,724 Plant Hatch (nuclear) 50.1 873 650 Plant Wansley (coal) 53.5 300 150 Plant Scherer (coal) Units 1 and 2 8.4 112 53 Unit 3 75.0 545 207 Plant McIntosh Common Facilities 75.0 19 2 (combustion-turbine) Rocky Mountain 25.4 169* 72 (pumped storage) Intercession City 33.3 11 1 (combustion-turbine) - --------------------------------------------------------------------
* Investment net of write-offs.
7. LONG-TERM POWER SALES AND LEASE AGREEMENTS
The Company and the other integrated Southeast utilities of Southern Company have long-term contractual agreements for the sale of capacity and energy to non-affiliated utilities located outside the system's service area. These
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NOTES (continued) Georgia Power Company 2000 Annual Report
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) 2000 $ 30 124 1999 32 162 1998 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 2000 with a minimum of three years notice until the expiration of the contracts in 2010.
During 2000, the Company entered into certain operating leases for portions of its generating unit capacity. Minimum future capacity revenues from noncancelable operating leases as of December 31, 2000 were as follows:
Year Minimum Obligations -------------------------- (in millions) 2001 $ 41 2002 45 2003 45 2004 45 2005 5 2006 and beyond - - ----------------------------------------------------------------- Total minimum obligations $181 =================================================================
8. INCOME TAXES
At December 31, 2000, tax-related regulatory assets were $566 million and tax-related regulatory liabilities were $247 million. The assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. The liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
2000 1999 1998 ------------------------------- Total provision for income taxes: (in millions) Federal: Current $ 342 $333 $415 Deferred (34) (34) (87) Deferred investment tax credits - - 7 - ----------------------------------------------------------------- 308 299 335 - ----------------------------------------------------------------- State: Current 48 54 77 Deferred (5) (6) (13) Deferred investment tax credits 10 5 - - ----------------------------------------------------------------- Total $361 $352 $399 =================================================================
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:
2000 1999 ------------------------ (in millions) Deferred tax liabilities: Accelerated depreciation $ 1,755 $1,766 Property basis differences 683 729 Other 243 155 - ------------------------------------------------------------------ Total 2,681 2,650 - ------------------------------------------------------------------ Deferred tax assets: Other property basis differences 189 200 Federal effect of state deferred taxes 91 93 Other deferred costs 208 109 Other 37 48 - ------------------------------------------------------------------ Total 525 450 - ------------------------------------------------------------------ Net deferred tax liabilities 2,156 2,200 Portion included in current assets 27 3 - ------------------------------------------------------------------ Accumulated deferred income taxes in the Balance Sheets $ 2,183 $2,203 ==================================================================
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 2000 and 1999, and $22 million in 1998. At December 31, 2000, all investment tax credits available to reduce federal income taxes payable had been utilized.
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NOTES (continued) Georgia Power Company 2000 Annual Report
A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
2000 1999 1998 -------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 2 2 6 Other (2) (2) (4) - --------------------------------------------------------------- Effective income tax rate 39% 39% 41% ===============================================================
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.
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. At December 31, 2000, $891 million 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. If additional first mortgage bonds are issued, supplemental indentures in connection with those issues may contain more stringent restrictions than those currently in effect. 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
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 $378.8 million of its first mortgage bonds outstanding at December 31, 2000, which are pledged as security for its obligations under pollution control revenue contracts. No interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase or loan agreements.
Senior Notes
In February 2000 and February 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, including its first mortgage bonds.
Bank Credit Arrangements
At the beginning of 2001, the Company had unused credit arrangements with banks totaling $1.8 billion, of which $1.3 billion expires at various times during 2001, 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 20, 2001, 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
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NOTES (continued) Georgia Power Company 2000 Annual Report
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 2001 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, 2000 was $979 million.
In addition, the Company borrows under uncommitted lines of credit with banks and through a $750 million commercial paper program that has the liquidity support of committed bank credit arrangements. Average compensating balances held under these committed facilities were not material in 2000.
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, 2000 and 1999, the Company had a capitalized lease obligation for its corporate headquarters building of $87 million with an interest rate of 8.1 percent. The lease agreement provides for payments that are minimal in early years and escalate through the first 21 years of the lease. 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 is being deferred as a cost to be recovered in the future as ordered by the GPSC. At December 31, 2000 and 1999, the interest and lease amortization deferred on the Balance Sheets are $55 million and $54 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.
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:
2000 1999 ------------------- (in millions) Bond improvement fund requirements $ - $ 5 Capital lease - current portion 2 1 First mortgage bond maturities and redemptions - 100 Pollution control bond maturities and redemptions - 50 - --------------------------------------------------------------- Total long-term debt $2 $156 ===============================================================
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.
Redemption of Securities
The Company plans to continue, to the extent possible, a program of redeeming or replacing debt and preferred securities in cases where opportunities exist to reduce financing costs. Issues may be repurchased in the open market or called at premiums as specified under terms of the issue. They may also be redeemed at face value to meet improvement fund requirements, to meet replacement provisions of the mortgage, or through use of proceeds from the sale of property pledged under the mortgage.
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NOTES (continued) Georgia Power Company 2000 Annual Report
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 2000 and 1999 is as follows:
Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock - --------------------------------------------------------------------- (in millions) -------------------------------------------- March 2000 $ 992 $223 $ 94 June 2000 1,221 311 148 September 2000 1,545 537 283 December 2000 1,113 162 34
March 1999 $ 931 $224 $ 92 June 1999 1,092 299 138 September 1999 1,466 557 296 December 1999 968 115 15 - ---------------------------------------------------------------------
Under the GPSC retail rate order, the Company recorded $135 million and $85 million of accelerated amortization in 2000 and 1999, respectively, which were recorded monthly as an operating expense. The fourth quarter December 1999 operating income has been restated to reflect the accelerated amortization as an operating expense rather than as amortization of premium on reacquired debt. See Note 3 to the financial statements under "Retail Rate Order" for additional information.
The Company's business is influenced by seasonal weather conditions.
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GULF POWER COMPANY
FINANCIAL SECTION
II-111
MANAGEMENT'S REPORT Gulf Power Company 2000 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 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 Comptroller and Chief Financial Officer
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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, 2000 and 1999, 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, 2000. 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-123 through II-137) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Atlanta, Georgia February 28, 2001
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 2000 net income after dividends on preferred stock was $51.8 million, a decrease of $1.9 million from the previous year. In 1999, earnings were $53.7 million, down $2.8 million when compared to 1998. The decrease in earnings in 2000, as well as 1999, was primarily a result of higher expenses than in the prior year.
Revenues
Operating revenues increased in 2000 when compared to 1999. The following table summarizes the change in operating revenues for the past two years:
Increase (Decrease) Amount From Prior Year ------------------------------------- 2000 2000 1999 ------------------------------------- (in thousands) Retail -- Base Revenues $336,103 $3,771 $2,469 Regulatory cost recovery and other 226,059 45,631 1,173 - ------------------------------------------------------------------ Total retail 562,162 49,402 3,642 - ------------------------------------------------------------------ Sales for resale-- Non-affiliates 66,890 4,537 461 Affiliates 66,995 885 23,468 - ------------------------------------------------------------------ Total sales for resale 133,885 5,422 23,929 Other operating revenues 18,272 (14,604) (3,990) - ------------------------------------------------------------------ Total operating revenues $714,319 $40,220 $23,581 ================================================================== Percent change 6.0% 3.6% - ------------------------------------------------------------------
Retail revenues of $562.2 million in 2000 increased $49.4 million, or 9.6 percent, from the prior year due primarily to the recovery of higher fuel and purchased power costs. Retail base rate revenues increased $3.8 million due to increased customer growth and hotter than normal weather, offset by a $10 million permanent annual rate reduction and $6.9 million of revenues subject to refund based upon the current retail revenue sharing plan (See Note 3 to the financial statements under "Retail Revenue Sharing Plan" for further information). Retail revenues for 1999 increased $3.6 million, or 0.7 percent, when compared to 1998 due primarily to an increase in the number of retail customers served by the Company.
The 2000 increase in regulatory cost recovery and other retail revenues over 1999 is primarily attributable to higher fuel and purchased power costs. The 1999 increase in regulatory cost recovery and other retail revenues over 1998 is primarily attributable to the recovery of increased purchased power capacity costs. "Regulatory cost recovery and other" includes the following: recovery provisions for fuel expense and the energy component of purchased power costs; energy conservation costs; purchased power capacity costs; and environmental compliance costs. 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 $133.9 million in 2000, an increase of $5.4 million, or 4.2 percent, over 1999 primarily due to additional energy sales. 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:
2000 1999 1998 ---------------------------------------- (in thousands) Capacity $20,270 $19,792 $22,503 Energy 21,922 20,251 14,556 - ------------------------------------------------------------- Total $42,192 $40,043 $37,059 =============================================================
Capacity revenues increased slightly in 2000 due to the recovery of higher operating expenses experienced during the year. Capacity revenues had been declining in prior years due to the decreasing net investment related to these sales. This downward trend accelerated during 1999 as a result of a reduction in the authorized rate of return on the equity component of the investment.
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 decreased in 2000 and in 1999 due primarily to the retail recovery clause adjustments for the difference between recoverable costs and the amounts actually reflected in current rates. See Notes 1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery," respectively, for further discussion.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2000 Annual Report
Energy Sales
Kilowatt-hour sales for 2000 and the percent changes by year were as follows:
KWH Percent Change ---------------------------------- 2000 2000 1999 ---------------------------------- (millions) Residential 4,790 7.1% 0.8% Commercial 3,379 4.9 3.6 Industrial 1,925 4.3 0.7 Other 19 0.0 0.0 -------- Total retail 10,113 5.8 1.7 Sales for resale Non-affiliates 1,705 9.2 16.4 Affiliates 1,917 (23.7) 42.9 -------- Total 13,735 0.7 9.0 =======================================================
In 2000, total retail energy sales increased when compared to 1999 due primarily to an increase in the total number of customers and hotter than normal weather. Total retail energy sales increased in 1999 when compared to 1998 due to increases in the number of customers. See "Future Earnings Potential" for information on the Company's initiatives to remain competitive and to meet conservation goals set by the Florida Public Service Commission (FPSC).
An increase in energy sales for resale to non-affiliates of 9.2 percent in 2000 when compared to 1999 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 2000 increased $39.5 million, or 7.1 percent, over the amount recorded in 1999 due primarily to higher fuel and purchased power expenses. In 1999, total operating expenses increased $26.8 million, or 5.1 percent, compared to 1998 due primarily to higher fuel, purchased power, and maintenance expenses offset by lower other operation expenses.
Fuel expenses in 2000, when compared to 1999, increased $6.7 million, or 3.2 percent, due primarily to an increase in average fuel costs. In 1999, fuel expenses increased $11.5 million, or 5.9 percent, when compared to 1998. The increases were the result of increased generation resulting from a higher demand for energy.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
2000 1999 1998 ------------------------------- Total generation (millions of kilowatt-hours) 12,866 13,095 11,986 Sources of generation (percent) Coal 98.2 97.4 98.0 Oil and gas 1.8 2.6 2.0 Average cost of fuel per net kilowatt-hour generated (cents)-- 1.68 1.60 1.69 - ---------------------------------------------------------------------
Purchased power expenses increased in 2000 by $25.5 million, or 44.7 percent, over 1999 and purchased power expenses for 1999 increased over 1998 by $13.2 million, or 30.2 percent, due primarily to a higher demand for energy in both years.
Depreciation and amortization expense increased $2.3 million, or 3.5 percent, in 2000 when compared to 1999, 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. The $5.5 million, or 9.2 percent, increase in 1999 compared to 1998 was due primarily to a reduction in the amortization of gains from the 1998 sale of emission allowances.
Interest on long-term debt, which is included in "Interest expense", increased $1.2 million, or 5.8 percent, in 2000 when compared to 1999 due primarily to the issuance of $50 million of senior notes in August 1999. In 1999 interest on long-term debt increased $1.7 million, or 8.4 percent, when compared to 1998 due primarily to the maturity of two first mortgage bond series in 1998 which were replaced by senior notes at a slightly higher interest rate, and 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2000 Annual Report
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
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 cost 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 $5.8 million in 2000. Pension income in 2001 is expected to be less as a result of plan amendments. Future pension income is dependent on several factors including trust earnings and changes to the plan.
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 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 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. 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 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 is currently planning to seek additional rate relief to recover costs related to the Smith Unit 3 combined cycle facility currently under construction and scheduled to be placed in-service in June of 2002.
For calendar year 2000, the Company's retail revenue range for sharing was $352 million to $368 million. Actual retail revenues in 2000 were $362.4 million and the Company recorded revenues subject to refund of $6.9 million. The estimated refund with interest was reflected in customer billings in February 2001. For calendar year 2001, the Company's retail revenue range for sharing is $358 million to $374 million. 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.
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. The Company is aggressively working to maintain and expand its share of wholesale sales in the southeastern power markets.
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
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tax issues. The commission's final report and recommendations are due to the Governor and legislature by December 1, 2001. The commission submitted an interim report to the state legislature that involves introducing more competition into the wholesale production of electricity in Florida. If approved by the legislature, the proposal would require utilities to turn over generating assets to an unregulated affiliate company over a 6-year transition period. The proposal would allow out of state companies to build merchant facilities and to bid on new generation needs. The effects of any proposed changes cannot presently be determined, but could have a material effect on the Company's financial statements.
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 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 current energy crisis in California. As a result of this crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. The inability of a company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on 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 1996, the FPSC approved a new optional Commercial/Industrial Service Rider (CISR), which is applicable to the rate schedules for the Company's largest existing and potential customers who are able to show they have viable alternatives to purchasing the Company's energy services. The CISR, approved as a pilot program, provides the flexibility needed to enable the Company to offer its services in a more competitive manner to these customers. The publicity of the CISR ruling, increased competitive pressures, and general awareness of customer choice pilots and proposals across the country have stimulated interest on the part of customers in custom tailored offerings. The Company has participated in one-on-one discussions with many of these customers, and has negotiated and executed two Contract Service Agreements within the CISR pilot program. The pilot program was scheduled to end in 2000; however, on February 6, 2001 the FPSC approved the Company's request to remove the original 48 month limitation and allow the program to continue.
Every five years the FPSC establishes numeric demand side management goals. The Company proposed numeric goals for the ten-year period from 2000 to 2009. The proposed goals consisted of the total, cost-effective winter and summer peak demand (kilowatts) and annual energy (kilowatt-hour) savings reasonably achievable from demand side management for the residential and commercial/industrial classes. The Company submitted its 2001 Demand Side Management Plan to the FPSC on December 29, 2000. The plan describes the proposed programs the Company will employ to reach the numeric goals. The plan relies heavily on innovative pricing and energy efficient construction.
On December 20, 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. After participating in regional conferences with customers and other members of the public to discuss the formation of RTOs, utilities were required to make a filing with the FERC. Southern Company and its integrated utility subsidiaries, including the Company, filed on October 16, 2000, a proposal for the creation of an RTO. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of the Company and any other participating utilities. Participants would have the option to either maintain their ownership or divest, sell, or lease their assets to the proposed RTO. If the FERC accepts the proposal as filed, the creation of
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an RTO is not expected to have a material impact on the Company's financial statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators to sell power largely free of 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 aggressively working to maintain and expand its share of wholesale sales in the southeastern power markets. In January 2001, Southern Company announced the formation of a new subsidiary -- Southern Power Company. The new subsidiary will own, manage, and finance wholesale generating assets in the Southeast. Southern Power will be the primary growth engine for Southern Company's market-based energy business. Energy from its assets will be marketed to wholesale customers under the Southern Company name.
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."
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.
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates 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, 2000, exposure from these activities was not material.
New Accounting Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. Statement No. 133 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 Company may utilize financial instruments to reduce its exposure to changes in interest rates depending on market conditions. The Company also enters into commodity related forward contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales.
Substantially all of these bulk energy purchases and sales meet the definition of a derivative under Statement No. 133. In many cases, these transactions meet the normal purchase and sale exception and the related contracts will continue to be accounted for under the accrual method. Certain of these instruments qualify as cash flow hedges resulting in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness will be recognized currently in net income. However, others will be required to be marked to market through current period income.
The Company adopted Statement No. 133 effective January 1, 2001. The impact on net income was immaterial. The application of the new rules is still evolving and further guidance from FASB is expected, which could additionally impact the Company's financial statements. Also, as wholesale energy markets mature, future transactions could result in more volatility in net income and comprehensive income.
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Financial Condition
Overview
The Company's financial condition continues to be very solid. During 2000, gross property additions were $95.8 million. Funds for the property additions were provided by operating activities. See the Statements of Cash Flows for further details.
Financing Activities
In 2000, there were no issuances or retirements of long-term debt. In 1999, the Company sold $50 million of senior notes and long-term bank notes totaling $27 million were retired. See the Statements of Cash Flows for further details.
Composite financing rates for the years 1998 through 2000 as of year end were as follows:
2000 1999 1998 ----------------------------- Composite interest rate on long-term debt 6.2% 6.0% 6.1% Composite rate on trust preferred securities 7.3% 7.3% 7.3% Composite preferred stock dividend rate 5.1% 5.1% 5.1% - -----------------------------------------------------------------
The composite interest rate on long-term debt increased in 2000 due to higher interest rates on variable rate pollution control bonds.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $451 million for the three years beginning in 2001 ($279 million in 2001, $96 million in 2002, and $76 million in 2003). These amounts include $199.2 million for the years 2001 and 2002 for the estimated 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.
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. As a result of a systemwide compliance strategy, some 50 generating units of Southern Company were brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $300 million for Southern Company, including 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. Compliance for Phase II and initial ozone non-attainment requirements increased Southern Company's total construction expenditures through 2000 by approximately $100 million. Phase II compliance did not have a material impact on Gulf Power.
A significant portion of costs related to the acid rain and ozone nonattainment 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2000 Annual Report
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 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 recently dismissed certain challenges but 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 will address other legal challenges to these standards in mid-2001. If the standards are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction rule to the states for implementation. Compliance is required by May 31, 2004. The final rule affects 21 states, including Georgia. 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 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 (MACT) provisions of the Clean Air Act. This determination is being challenged in the courts. 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 will likely be required around 2010. Litigation of the BART rules is probable in the near future.
Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C. add to the uncertainties associated with BART guidance and the MACT determination for mercury and other HAPS.
The EPA and state environmental regulatory agencies are also reviewing and evaluating various other matters including: nitrogen oxide emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; 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. 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 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 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2000 Annual Report
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. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. The EPA did not include the system service company in the new complaint. Southern Company believes that its integrated utilities 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.
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, 2000, the Company had approximately $4.4 million of cash and cash equivalents and $53.5 million of unused committed lines of credit with banks to meet its short-term cash needs. Refer to the Statements of Cash Flows for details related to the Company's financing activities. See Note 4 to the financial statements under "Bank Credit Arrangements" for additional information.
The Company historically has relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control revenue 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 2000 Annual Report contains forward looking and historical information. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "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 extent and timing of the entry of additional competition in the markets of the Company; potential business strategies, including acquisitions or dispositions of assets or
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businesses, which cannot be assured to be completed or beneficial; internal restructuring or other restructuring options, that may be pursued by the registrants; state and federal rate regulation in the United States; political, legal and economic conditions and developments in the United States; financial market conditions and the results of financing efforts; the impact of fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 2000 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Gulf Power Company is a wholly owned subsidiary of Southern Company, which is the parent company of five integrated Southeast utilities, Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Mirant Corporation (Mirant) - formerly Southern Energy, Inc., -- Southern Nuclear Operating Company (Southern Nuclear), and other direct and indirect subsidiaries. The integrated Southeast utilities -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four states. Gulf Power Company provides electric service to the northwest panhandle of Florida. Contracts among the integrated Southeast utilities -- 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 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 Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Mirant acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Mirant businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
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.
Related-Party 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 $44 million, $43 million, and $40 million during 2000, 1999, and 1998, 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:
2000 1999 -------------------------- (in thousands) Deferred income tax charges $ 15,963 $ 25,264 Deferred loss on reacquired debt 15,866 17,360 Environmental remediation 7,638 5,745 Vacation pay 4,512 4,199 Regulatory clauses under (over) recovery, net (4,736) 8,486 Accumulated provision for rate refunds (7,203) - Accumulated provision for property damage (8,731) (5,528) Deferred income tax credits (38,255) (49,693) Other, net (1,074) (1,255) - ------------------------------------------------------------------ Total $ (16,020) $ 4,578 ==================================================================
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NOTES (continued) Gulf Power Company 2000 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 any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value.
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 3.8 percent in 2000, 1999, and 1998. 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.
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. The Company is included in the consolidated federal income tax return of Southern Company.
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.
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
The Company's 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, 2000 $365,993 $364,697 At December 31, 1999 $367,449 $349,791 Capital trust preferred securities: At December 31, 2000 $85,000 $80,988 At December 31, 1999 $85,000 $69,092 - --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on either closing market prices or closing prices of comparable instruments.
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NOTES (continued) Gulf Power Company 2000 Annual Report
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 $1.2 million and $1.8 million at December 31, 2000 and 1999, 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, 2000 and 1999, the accumulated provision for property damage was $8.7 million and $5.5 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 $3.5 million in 2000, $5.5 million in 1999, and $6.5 million in 1998 to the accumulated provision for property damage. The Company charged $0.3 million, $1.6 million, and $4.2 million against the provision account in 2000, 1999, and 1998 respectively.
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 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 effects of these changes will be to increase the Company's annual pension and postretirement benefits costs by approximately $1.2 million and $0.6 million, respectively. 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 --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $141,967 $143,012 Service cost 4,282 4,490 Interest cost 10,394 9,440 Benefits paid (6,973) (6,862) Actuarial gain and employee transfers, net (689) (8,113) - --------------------------------------------------------------- Balance at end of year $148,981 $141,967 ===============================================================
Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $241,485 $212,934 Actual return on plan assets 43,833 35,971 Benefits paid (6,973) (6,862) Employee transfers 4,921 (558) - --------------------------------------------------------------- Balance at end of year $283,266 $241,485 ===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in thousands) Funded status $ 134,286 $ 99,518 Unrecognized transition obligation (3,602) (4,323) Unrecognized prior service cost 4,121 4,495 Unrecognized net gain (111,314) (81,956) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 23,491 $ 17,734 ===============================================================
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NOTES (continued) Gulf Power Company 2000 Annual Report
Components of the pension plan's net periodic cost were as follows:
2000 1999 1998 - ------------------------------------------------------------------- Service cost $ 4,282 $ 4,490 $ 4,107 Interest cost 10,394 9,440 9,572 Expected return on plan assets (17,504) (15,968) (14,827) Recognized net gain (2,582) (1,579) (1,891) Net amortization (347) (347) (347) - ------------------------------------------------------------------- Net pension income $ (5,757) $ (3,964) $ (3,386) ===================================================================
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 --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $48,010 $49,303 Service cost 896 1,087 Interest cost 3,515 3,261 Benefits paid (1,462) (1,177) Actuarial gain and employee transfers, net (934) (4,464) - --------------------------------------------------------------- Balance at end of year $50,025 $48,010 ===============================================================
Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $11,196 $ 9,603 Actual return on plan assets 2,079 1,525 Employer contributions 1,575 1,245 Benefits paid (1,462) (1,177) - --------------------------------------------------------------- Balance at end of year $13,388 $11,196 ===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in thousands) Funded status $(36,638) $(36,814) Unrecognized transition obligation 4,368 4,723 Unrecognized prior service cost 2,582 2,741 Unrecognized net loss 496 2,620 Fourth quarter contributions 316 300 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(28,876) $(26,430) ===============================================================
Components of the postretirement plan's net periodic cost were as follows:
2000 1999 1998 - ---------------------------------------------------------------- Service cost $ 896 $1,087 $ 946 Interest cost 3,515 3,261 3,123 Expected return on plan assets (901) (794) (717) Transition obligation 355 356 356 Prior service cost 159 159 119 Recognized net loss 13 264 128 - ---------------------------------------------------------------- Net postretirement cost $4,037 $4,333 $3,955 ================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits were:
2000 1999 - -------------------------------------------------------- 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 7.3 percent for 2000, decreasing gradually to 5.5 percent through the year 2005, and remaining at that level thereafter.
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NOTES (continued) Gulf Power Company 2000 Annual Report
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, 2000 as follows (in thousands):
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- Benefit obligation $3,187 $2,874 Service and interest costs $278 $247 ===============================================================
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 2000, 1999, and 1998 were $2.2 million, $2.0 million, and $2.0 million, respectively.
Work Force Reduction Programs
The Company recorded costs related to work force reduction programs of $0.6 million in 2000, $0.2 million in 1999, and $2.8 million in 1998. The Company has also incurred its pro rata share for the costs of affiliated companies' programs. The costs related to these programs were $1.2 million for 2000, $0.6 million for 1999, and $0.2 million for 1998. The Company has expensed all costs related to these work force reduction programs.
3. CONTINGENCIES AND REGULATORY MATTERS
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 all 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 2000, 1999, and 1998, the Company recorded ECRC revenues of $9.9 million, $11.5 million, and $8.0 million, respectively.
At December 31, 2000, the Company's liability for the estimated costs of environmental remediation projects for known sites was $7.6 million. These estimated costs are expected to be expended from 2001 through 2006. 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 $6.4 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 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 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 equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The Company believes that its integrated utilities 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
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NOTES (continued) Gulf Power Company 2000 Annual Report
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 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 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 is currently planning to seek additional rate relief to recover costs related to the Smith Unit 3 combined cycle facility scheduled to be placed in-service in June of 2002.
For calendar year 2000, the Company's retail revenue range for sharing was $352 million to $368 million to be shared between the Company and its retail customers on the one-third/two-thirds basis. Actual retail revenues in 2000 were $362.4 million and the Company recorded revenues subject to refund of $6.9 million. The estimated refund with interest of $0.3 million was reflected in customer billings in February 2001. In addition to the refund the Company amortized $1 million of the regulatory assets related to the corporate office. For calendar year 2001, the Company's retail revenue range for sharing is $358 million to $374 million. 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.
4. FINANCING AND COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $279 million in 2001, $96 million in 2002, and $76 million in 2003. 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, 2000, significant purchase commitments were outstanding in connection with the construction program. The Company has budgeted $199.2 million for the years 2001 and 2002 for the estimated 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.
Bank Credit Arrangements
At December 31, 2000, the Company had $61.5 million of lines of credit with banks subject to renewal June 1 of each year, of which $53.5 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. In addition, the Company has bid-loan facilities with seven major money center banks that total $130 million, of which $35 million was committed at December 31, 2000.
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.
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NOTES (continued) Gulf Power Company 2000 Annual Report
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, 2000 were as follows:
Year Fuel --------- ---------------- (in millions) 2001 $139 2002 91 2003 90 2004 92 2005 93 2006-2024 473 ------------------------------------------------------------- Total commitments $978 =============================================================
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 renew the lease. In 1997, three additional lease agreements for 120 cars each were entered into for three years, with a monthly renewal option for up to an additional nine months.
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 $2.1 million in 2000 and $2.8 million in 1999. The annual amounts for 2001 through 2005 are expected to be $1.9 million, $1.9 million, $1.9 million, $2.0 million, and $2.0 million, respectively, and after 2005 are expected to total $13.8 million.
5. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel, a steam-electric 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 the plant.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant Scherer is a steam-electric 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, 2000, the Company's percentage ownership and its investment in these jointly owned facilities were as follows:
Plant Scherer Plant Unit No. 3 Daniel (coal-fired) (coal-fired) ----------------------------- (in thousands) Plant In Service $185,778(1) $232,074 Accumulated Depreciation $70,207 $118,504 Construction Work in Progress $252 $2,006
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: 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 $20.3 million in 2000, $19.8 million in 1999, and $22.5 million in 1998.
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NOTES (continued) Gulf Power Company 2000 Annual Report
Capacity revenues increased slightly in 2000 due to the recovery of higher operating expenses experienced during the year.
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, 209 megawatts of net dependable capacity were sold by the Company during 2000. Sales will increase slightly to 210 megawatts per year in 2001 and remain close to that level, 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.
7. INCOME TAXES
At December 31, 2000, the tax-related regulatory assets to be recovered from customers were $16.0 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, 2000, the tax-related regulatory liabilities to be credited to customers were $38.3 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:
2000 1999 1998 ------------------------------------ (in thousands) Total provision for income taxes: Federal-- Current $37,250 $33,973 $31,746 Deferred (11,159) (6,107) (4,467) - -------------------------------------------------------------------- 26,091 27,866 27,279 - -------------------------------------------------------------------- State-- Current 5,796 5,267 5,137 Deferred (1,357) (502) (217) - -------------------------------------------------------------------- 4,439 4,765 4,920 - -------------------------------------------------------------------- Total $30,530 $32,631 $32,199 ====================================================================
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:
2000 1999 --------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $172,646 $168,662 Other 14,262 24,272 - --------------------------------------------------------------------- Total 186,908 192,934 - --------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 8,703 9,293 Postretirement benefits 9,205 8,456 Other 14,742 12,526 - --------------------------------------------------------------------- Total 32,650 30,275 - --------------------------------------------------------------------- Net deferred tax liabilities 154,258 162,659 Less current portion, net (816) (117) - --------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $155,074 $162,776 =====================================================================
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 $1.9 million in 2000, 1999, and 1998. At December 31, 2000, 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:
2000 1999 1998 ---------------------------- 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 (1) - (2) - ---------------------------------------------------------------- Effective income tax rate 37% 38% 36% ================================================================
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.
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NOTES (continued) Gulf Power Company 2000 Annual Report
8. COMPANY OBLIGATED MANDATORILY REDEEMABLE 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.
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 and Trust II. Trust I and Trust II are subsidiaries of the Company, and accordingly are consolidated in the Company's financial statements.
9. SECURITIES DUE WITHIN ONE YEAR
At December 31, 2000, the Company had an improvement fund requirement of $850,000. 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.
10. COMMON STOCK 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, 2000, retained earnings of $127 million were restricted against the payment of cash dividends on common stock under the terms of the mortgage indenture.
11. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 2000 and 1999 are as follows:
Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock - -------------------------------------------------------------------- (in thousands) 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
March 1999 $134,506 $15,665 $ 4,799 June 1999 166,815 29,253 13,226 September 1999 218,264 54,429 28,582 December 1989 154,514 19,815 7,060 - --------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.
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MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Mississippi Power Company 2000 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 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 upon 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/Dwight H. Evans Dwight H. Evans President and Chief Executive Officer
/s/Michael W. Southern Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 2000 and 1999, 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, 2000. 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 11-151 through II-166) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Atlanta, Georgia February 28, 2001
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's 2000 net income after dividends on preferred stock of $55 million increased $0.2 million over 1999 earnings of $54.8 million, which were $0.3 million less than 1998 earnings of $55.1 million.
Revenues
Operating revenues for the Company in 2000 and the changes from the prior year are as follows:
Increase (Decrease) Amount From Prior Year ------ ---------------------- 2000 2000 1999 --------------------------------------- (in millions) Retail -- Base Revenues $287,253 $ (5,854) $ 17,462 Fuel cost recovery and other 211,298 34,971 9,405 ---------------------------------------------------------------- Total retail 498,551 29,117 26,867 ---------------------------------------------------------------- Sales for resale -- Non-affiliates 145,931 14,927 9,779 Affiliates 27,915 8,469 1,161 ---------------------------------------------------------------- Total sales for resale 173,846 23,396 10,940 Other operating revenues 15,205 2,085 66 ---------------------------------------------------------------- Operating revenues $687,602 $54,598 $ 37,873 ================================================================== Percent change 8.6% 6.4% ------------------------------------------------------------------
Total retail revenues for 2000 increased approximately 6.2 percent when compared to 1999. The increase resulted primarily from continued growth in the service area, a positive impact of weather and additional fuel revenues. Retail revenues for 1999 reflected a 6.1 percent increase over the prior year due to the continued growth in the service area, increased fuel revenues, and a true-up of the unbilled revenue estimate.
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.
Energy sales to non-affiliates include economy sales and amounts sold under short-term contracts. 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 increased 10.9 percent in 2000 and 10.2 percent in 1999, with the related revenues rising 10.8 percent and 12.1 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 2000 and 1999 primarily due to power marketing activities. These increases were offset by increases in purchased power from non-affiliates and, as a result, had no significant effect on net income.
Sales to affiliated companies within the Southern Company electric system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales have no material impact on earnings.
Below is a breakdown of kilowatt-hour sales for 2000 and the percent change for the last two years:
2000 Percent Change ------------- --------------------------- KWH 2000 1999 --------------------------- (in millions) Residential 2,286 1.7% - Commercial 2,883 1.3 8.5% Industrial 4,376 (0.7) 18.2 Other 41 2.5 0.8 ------- Total retail 9,586 0.5 10.4 Sales for Resale -- Non-affiliates 3,675 12.9 3.1 Affiliates 453 (16.2) (2.2) ------- Total 13,714 2.8 8.0 ==================================================================
Total retail kilowatt-hour sales increased slightly in 2000 when compared to 1999 sales, which included an unbilled revenue true-up of approximately 3.5 percent. The increase primarily resulted from the continued growth in the service area and the positive impact of weather. Excluding the impact of the unbilled revenue true-up, all retail customer classes experienced growth in 2000
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2000 Annual Report
due to the positive impact of weather, increased tourism, and continued growth in the service area. In 1999, increased tourism and strong growth impacted commercial sales, while industrial sales were impacted by increased production by several larger industrial customers, including one which was shut down in 1998 by Hurricane Georges.
Expenses
Total operating expenses were $565 million in 2000 reflecting an increase of $52 million or 10.1 percent over the prior year. The increase was due primarily to higher fuel and purchased power expenses. In 1999, total operating expenses increased by 6.9 percent over the prior year due primarily to higher fuel expenses.
Fuel costs are the single largest expense for the Company. Fuel expenses for 2000 and 1999 increased 10.7 percent and 10.3 percent, respectively. The increase for each year was due to increased generation and a higher average cost of fuel. The increased generation was due to higher demand for energy across the Southern Company electric system.
In 2000, expenses related to purchased power from non-affiliates increased 40.0 percent, while expenses related to purchased power from affiliates increased 64.7 percent which, in total, resulted in a 51 percent increase when compared to 1999. This increase consisted mostly of energy purchased for power marketing activities which was resold to non-affiliated third parties and had no significant effect on net income. 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:
2000 1999 1998 ----------------------------- Total generation (millions of kilowatt hours) 11,688 11,599 10,610 Sources of generation (percent) -- Coal 83 81 80 Gas 17 19 20 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.80 1.65 1.62 - -----------------------------------------------------------------
Other operation expenses decreased 8.2 percent in 2000 primarily due to a decrease in administrative and general expenses. In 1999, other operation expense increased 13.9 percent primarily due to the amortization of costs associated with the workforce reduction plan and higher distribution expenses. Maintenance expense in 2000 increased due to additional scheduled maintenance, while maintenance expense in 1999 decreased due to reduced scheduled maintenance. In 2000, depreciation expenses increased slightly due to growth in plant investment and a new composite depreciation rate, which became effective January 2000. Comparisons of taxes other than income taxes for 2000 and 1999 show increases of 1.7 percent and 4.2 percent, respectively, due to higher municipal franchise taxes resulting from higher retail revenues. Interest on long-term debt increased in 2000 due to higher interest rates and increased 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 or the partially offsetting gain that arises through financing facilities with
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2000 Annual Report
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
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors 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, 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 Environmental Compliance Overview Plan (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) regulations. 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's 2000 ECO Plan filed in January 2000 was approved as filed, and resulted in a slight decrease in customer prices. The Company filed its 2001 ECO Plan in January 2001 and, if approved as filed, it will result in a slight increase in customer prices. Refer to 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."
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.
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 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 transmission 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2000 Annual Report
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 transmission, prices, and recovery of any stranded costs. The inability of the Company to recover its investment, including regulatory assets, could have a material adverse effect on the financial condition of the Company.
The Company is attempting to minimize or reduce its cost exposure. 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 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.
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.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued its final ruling on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. After participating in regional conferences with customers and other members of the public to discuss the formation of RTOs, utilities were required to make a filing with the FERC. On October 16, 2000, Southern Company and its integrated utilities including the Company filed a proposal for the creation of an RTO. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of the Company and any other participating utilities. Participants would have the option to either maintain their ownership or divest, sell, or lease their assets to the proposed RTO. If the FERC accepts the proposal as filed, the creation of an RTO is not expected to have a material impact on the Company's financial statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators to sell power largely free of 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 aggressively working to maintain and expand its share of wholesale sales in the southeastern power markets. In January 2001, Southern Company announced the formation of a new subsidiary - Southern Power Company. The new subsidiary will own, manage, and finance wholesale generating assets in the Southeast. Southern Power will be the primary growth engine for Southern Company's market-based energy business. Energy from its assets will be marketed to wholesale customers under the Southern Company name.
In accordance with FASB Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income of approximately $4.2 million in 2000. Pension income in 2001 is expected to be less as a result of plan amendments. Future pension income is dependent on several factors including trust earnings and changes to the plan. For more information, see Note 2.
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 later under "Environmental Matters."
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.
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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, 2000, exposure from these activities was not material to the Company's financial statements. Also, based on the Company's overall interest rate exposure at December 31, 2000, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
New Accounting Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. Statement No. 133 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.
Substantially all of the Company's bulk energy purchases and sales meet the definition of a derivative under Statement No. 133. In many cases, these transactions meet the normal purchase and sale exception and the related contracts will continue to be accounted for under the accrual method. Certain of these instruments qualify as cash flow hedges resulting in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness will be recognized currently in net income. However, others will be required to be marked to market through current period income.
The Company adopted Statement No. 133 effective January 1, 2001. The impact on net income was immaterial. The application of the new rules is still evolving and further guidance from FASB is expected, which could additionally impact the Company's financial statements. Also, as wholesale energy markets mature, future transactions could result in more volatility in net income and comprehensive income.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition during 2000 was the addition of approximately $81 million to utility plant. Funding for these additions and other capital requirements were derived primarily from operations. The Statements of Cash Flows provide additional details.
Financing Activity
In March 2000, the Company issued $100 million of floating rate senior notes due March 28, 2002. The proceeds were used to prepay bank loans of $45 million maturing in November 2001 and $5 million maturing in October 2002. The balance of the $100 million was used to repay a portion of the Company's outstanding 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 increased for the year 2000 when compared to 1998 and 1999. As of year-end , the composite rates were as follows:
2000 1999 1998 ---------------------------- Composite interest rate on long-term debt 6.41% 6.19% 6.14%
Composite preferred stock dividend rate 6.33% 6.33% 6.33%
Composite interest rate on preferred securities 7.75% 7.75% 7.75% ------------------------------------------------------------
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa Funding, Limited Partnership ("Escatawpa"), that calls for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility. It is anticipated that the total project will cost approximately $400 million, and upon project completion in mid 2001, the Company intends to lease the facility for an initial term of approximately 10 years. It is anticipated that the annual lease payments will approximate $32 million during the initial term.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2000 Annual Report
Capital Structure
At year-end 2000, the Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, decreased from 50.2 percent in 1999, to 48.1 percent.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $191 million ($62 million in 2001, $60 million in 2002, and $69 million in 2003). 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.
Other Capital Requirements
In addition to the funds required for the Company's construction program, approximately $135 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.
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 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, 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 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 the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. The EPA did not include SCS in the new complaint. 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 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. 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. As a result of a systemwide compliance strategy, some 50 generating units of Southern Company were brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $300 million for Southern Company, including approximately $65 million for the Company.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2000 Annual Report
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 the Company's total construction expenditures through 2000 by approximately $100 million. 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 recently dismissed certain challenges but 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 will address other legal challenges to these standards in mid-2001. A decision is expected in the spring of 2001. If the standards are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May 31, 2004. The final rules affect 21 states that at present 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, 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 (MACT) provisions of the Clean Air Act. This determination is being challenged in the courts. 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 would likely be required around 2010. Litigation of the BART rules is probable in the near future.
Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C. add to the uncertainties associated with BART guidance and the MACT determination for mercury and other HAPS.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; 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 costs.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2000 Annual Report
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 lawsuits alleging damages caused by electromagnetic fields or other environmental concerns. The likelihood or outcome of such potential lawsuits cannot be determined at this time.
Sources of Capital
To meet short-term cash needs and contingencies, the Company had at December 31, 2000 approximately $7.5 million of cash and cash equivalents and approximately $117 million of unused committed credit agreements. The Company had $56 million of short-term notes payable outstanding at year-end 2000.
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 issued unsecured debt in 1998.
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.
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," "expects," "plans," "anticipates," "believes," "estimates," "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 against the Company; the extent and timing of the entry of additional competition in the markets of the Company; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; internal restructuring or other restructuring options, that may be pursued by the Company; state and federal rate regulation in the United States; political, legal and economic conditions and developments in the United States; financial market conditions and the results of financing efforts; the impact of fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
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NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 2000 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 integrated Southeast utilities, a system service company (SCS), Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern Nuclear), Mirant Corporation -- formerly Southern Energy, Inc. -- and other direct and indirect subsidiaries. The integrated Southeast utilities -- Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four states. Contracts among the integrated Southeast utilities -- 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). SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Mirant acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Mirant businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
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.
Related-Party 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 $46.2 million, $45.5 million, and $43.9 million during 2000, 1999, and 1998, 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:
2000 1999 ------------------------- (in thousands) Deferred income tax charges $ 13,860 $ 21,557 Vacation pay 5,701 5,218 Premium on reacquired debt 7,168 8,154 Property damage reserve (3,519) (3,082) Deferred income tax credits (25,603) (34,765) Other, net (505) (349) - ---------------------------------------------------------------- Total $ (2,898) $ (3,267) ================================================================
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NOTES (continued) Mississippi Power Company 2000 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 and certain qualifying environmental costs. 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 2000 and 3.3 percent in 1999 and 1998. 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
The Company's 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, 2000 $371 $362 At December 31, 1999 $353 $334 Capital trust preferred securities: At December 31, 2000 $35 $34 At December 31, 1999 $35 $30 - --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on either closing market price or closing price of comparable instruments.
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NOTES (continued) Mississippi Power Company 2000 Annual Report
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 2000, the Company provided for such costs by charges to income of $3.5 million. In 1999 and 1998, the Company provided for such costs by charges to income of $4.4 million and $1.5 million, respectively. As of December 31, 2000, the accumulated provision amounted to $3.5 million.
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 trusts to 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 effects of these changes will be to increase annual pension and postretirement benefits costs by approximately $1.3 and $0.4 million, respectively. 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 -------------------------- 2000 1999 - --------------------------------------------------------------------- (in thousands) Balance at beginning of year $139,930 $142,807 Service cost 4,272 4,415 Interest cost 10,196 9,377 Benefits paid (7,593) (8,050) Actuarial gain and employee transfers (1,419) (8,619) - --------------------------------------------------------------------- Balance at end of year $145,386 $139,930 =====================================================================
Plan Assets -------------------------- 2000 1999 - --------------------------------------------------------------------- (in thousands) Balance at beginning of year $221,487 $198,100 Actual return on plan assets 39,737 33,216 Benefits paid (7,593) (8,050) Employee transfers 3,017 (1,779) - --------------------------------------------------------------------- Balance at end of year $256,648 $221,487 =====================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------------- (in thousands) Funded status $111,263 $ 81,557 Unrecognized transition obligation (3,269) (3,814) Unrecognized prior service cost 4,577 4,991 Unrecognized net gain (105,847) (80,246) - --------------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 6,724 $ 2,488 =====================================================================
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Components of the plans' net periodic cost were as follows:
2000 1999 1998 - ------------------------------------------------------------------ (in thousands) Service cost $ 4,272 $ 4,415 $ 3,848 Interest cost 10,196 9,377 9,613 Expected return on plan assets (15,910) (14,681) (13,817) Recognized net gain (2,663) (1,721) (1,956) Net amortization (131) (131) (131) - ------------------------------------------------------------------ Net pension income $ (4,236) $ (2,741) $(2,443) ==================================================================
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 ---------------------------- 2000 1999 - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $45,390 $47,260 Service cost 830 982 Interest cost 3,309 3,105 Benefits paid (2,628) (2,256) Actuarial gain and employee transfers (1,949) (3,701) - ----------------------------------------------------------------- Balance at end of year $44,952 $45,390 =================================================================
Plan Assets ---------------------------- 2000 1999 - ------------------------------------------------------------------ (in thousands) Balance at beginning of year $14,998 $12,779 Actual return on plan assets 2,511 1,818 Employer contributions 2,961 2,657 Benefits paid (2,627) (2,256) - ----------------------------------------------------------------- Balance at end of year $17,843 $14,998 =================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2000 1999 - ---------------------------------------------------------------------- (in thousands) Funded status $(27,109) $(30,392) Unrecognized transition obligation 4,275 4,621 Unrecognized net gain (6,632) (3,406) Fourth quarter contributions 1,065 931 - ---------------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(28,401) $(28,246) ======================================================================
Components of the plans' net periodic cost were as follows:
2000 1999 1998 - -------------------------------------------------------------------- (in thousands) Service cost $ 830 $ 981 $ 806 Interest cost 3,309 3,105 3,162 Expected return on plan assets (1,235) (1,100) (989) Net amortization 346 346 346 - -------------------------------------------------------------------- Net postretirement cost $ 3,250 $ 3,332 $3,325 ====================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits were:
2000 1999 --------------------------------------------------------------- Discount 7.50% 7.50% Annual salary increase 5.00 5.00 Long-term return on plan assets 8.50 8.50 ---------------------------------------------------------------
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NOTES (continued) Mississippi Power Company 2000 Annual Report
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 7.29 percent for 2000, decreasing gradually to 5.50 percent through the year 2005 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, 2000 as follows:
1 Percent 1 Percent Increase Decrease - ----------------------------------------------------------------- (in thousands) Benefit obligation $2,669 $2,396 Service and interest costs 242 215 - -----------------------------------------------------------------
Workforce Reduction Program
In 1997, approximately one hundred employees of the Company accepted the terms of a workforce reduction plan. The cost incurred in connection with this voluntary plan was approximately $18 million. The MPSC approved the deferral and amortization of these program costs over a period not to exceed 60 months beginning no later than July 1998. As of December 31, 1999, the cost was fully amortized.
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 2000, 1999, and 1998 were $2.3 million, $2.2 million, and $2.1 million, respectively.
3. LITIGATION AND REGULATORY MATTERS
Environmental Litigation
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 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 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, 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 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. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. The EPA did not include SCS in the new complaint. 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 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 sharing rate adjustments based on the Company's ability to maintain low rates for customers and on the Company's performance as measured by three
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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. PEP will remain in effect until the MPSC modifies or terminates the plan. There were no PEP retail revenue changes for 2000, 1999, or 1998.
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 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 2001 ECO Plan in January and, if approved as filed, it 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, Financing and 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 ratebase 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.
4. FINANCING AND COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, the costs of which are currently estimated to total $62 million in 2001, $60 million in 2002, and $69 million in 2003. 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.
Financing
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa, that calls for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility. It is anticipated that the total project will cost approximately $400 million, and upon project completion in mid 2001, the Company intends to lease the facility for an initial term of approximately 10 years. It is anticipated that the annual lease payments will approximate $32 million during the initial term.
Bank Credit Arrangements
At December 31, 2000, the Company had total committed credit agreements with banks for approximately $117 million. At year-end 2000, the unused portion of these committed credit agreements was approximately $117 million. These credit agreements expire at various dates in 2001. 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
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agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. At December 31, 2000, the Company had $56 million of short-term borrowings outstanding.
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.
Lease Agreements
In 1984, the Company and Entergy Corp. (formerly Gulf States Utilities) entered into a forty-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 2000, use fees collected under this agreement, net of related expenses, amounted to approximately $3 million each year, and are included within Other Income in the Statements of Income.
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. In 1997, a third lease agreement for the use of 360 railcars was also entered into for three years, with a monthly renewal option for up to an additional nine months. All of these leases, totaling 1,105 railcars, were for the transport of coal to Plant Daniel.
Gulf Power, as joint owner of Plant Daniel, is responsible for one half of the lease cost. The Company's share (50%) of the leases, charged to fuel stock, was $2.1 million in 2000, $2.8 million in 1999, and $2.8 million in 1998. The Company's annual lease payments for 2001 through 2005 will average approximately $2.0 million and after 2005, lease payments total in aggregate approximately $14 million.
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.
Total estimated obligations at December 31, 2000 were as follows:
Year Fuel - ---- ---- (in millions) 2001 $ 294 2002 332 2003 313 2004 137 2005 95 2006 - 2024 131 Total commitments $1,302
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, 2000, 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% $63,346 $32,762
Daniel Units 1 and 2 1,000 50% $230,853 $115,472
-----------------------------------------------------------------------
The Company's share of plant operating expenses is included in the corresponding operating expenses in the Statements of Income.
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NOTES (continued) Mississippi Power Company 2000 Annual Report
6. LONG-TERM CAPACITY SALES AND LEASE AGREEMENTS
The Company and the other utility affiliates 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.
During 2000, the Company entered into a 10 year capacity lease that begins 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.
7. INCOME TAXES
At December 31, 2000, the tax-related regulatory assets and liabilities were $14 million and $26 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:
2000 1999 1998 ---------------------------------- (in thousands) Total provision for income taxes Federal -- Current $28,934 $33,379 $20,500 Deferred 622 (3,973) 9,442 ----------------------------------------------------------------- 29,556 29,406 29,942 ----------------------------------------------------------------- State -- Current 4,670 4,881 2,544 Deferred 130 (170) 2,178 ----------------------------------------------------------------- 4,800 4,711 4,722 ----------------------------------------------------------------- Total $34,356 $34,117 $34,664 =================================================================
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:
2000 1999 ----------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $151,278 $154,698 Basis differences 8,559 8,967 Other 24,136 23,108 --------------------------------------------------------------- Total 183,973 186,773 --------------------------------------------------------------- Deferred tax assets: Other property basis differences 17,147 21,003 Pension and other benefits 9,528 9,608 Property insurance 3,558 3,419 Unbilled fuel 5,727 4,846 Other 9,669 11,071 --------------------------------------------------------------- Total 45,629 49,947 --------------------------------------------------------------- Net deferred tax liabilities 138,344 136,826 Portion included in current assets, net 1,565 2,738 --------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $139,909 $139,564 ===============================================================
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 2000, 1999, and 1998. At December 31, 2000, 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:
2000 1999 1998 ---------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.4 3.3 Non-deductible book depreciation .6 .7 .5 Other (1.5) (1.6) (1.0) ------------------------------------------------------------------ Effective income tax rate 37.5% 37.5% 37.8% ==================================================================
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NOTES (continued) Mississippi Power Company 2000 Annual Report
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.
8. COMPANY OBLIGATED MANDATORILY REDEEMABLE 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 Trusts' 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.
9. 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:
2000 1999 --------------------- (in thousands) Bond improvement fund requirement $1,000 $1,000 Less: Portion to be satisfied by certifying property additions 1,000 1,000 --------------------------------------------------------------- Cash sinking fund requirement - - Current portion of other long-term debt - 30,000 Pollution control bond cash sinking fund requirements 20 20 --------------------------------------------------------------- Total $20 $30,020 ===============================================================
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.
10. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 2000, 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.
11. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 2000 and 1999 are as follows:
Net Income After Dividends Operating Operating On Preferred Quarter Ended Revenues Income Stock - -------------------------------------------------------------------- (in thousands) 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
March 1999 $122,435 $18,122 $7,193 June 1999 158,590 31,289 14,953 September 1999 201,594 51,609 27,313 December 1999 150,385 18,736 5,350 - --------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the timing of rate changes.
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SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Savannah Electric and Power Company 2000 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/G. Edison Holland, Jr. /s/K. R. Willis G. Edison Holland, Jr. K. R. Willis President Vice President, and Chief Executive Officer Treasurer, Chief Financial Officer and Assistant Secretary
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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, 2000 and 1999, 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, 2000. 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-179 through II-193) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Arthur Andersen LLP Atlanta, Georgia February 28, 2001
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 2000 Annual Report
RESULTS OF OPERATIONS - --------------------
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 2000 totaled $23.0 million, representing no significant change from the prior year.
In 1999, earnings were $23.1 million, representing a $0.6 million, or 2.4 percent decrease from the prior year. This was principally due to lower non-operating revenues.
Revenues
Total operating revenues for 2000 were $295.7 million, reflecting a 17.5 percent increase when compared to 1999. The following table summarizes the factors affecting operating revenues for the past two years:
Increase (Decrease) From Prior Year ------------------------- Amount 2000 2000 1999 -------------------------------------- (in thousands) Retail -- Base Revenues $161,807 $ 9,272 $ 376 Fuel cost recovery and other 120,815 31,085 (438) ----------------------------------------------------------------- Total retail 282,622 40,357 (62) ----------------------------------------------------------------- Sales for resale -- Non-affiliates 4,748 1,353 (1,153) Affiliates 4,974 823 1,135 ----------------------------------------------------------------- Total sales for resale 9,722 2,176 (18) ----------------------------------------------------------------- Other operating revenues 3,374 1,591 (2,781) ----------------------------------------------------------------- Total operating revenues $295,718 $44,124 $(2,861) ================================================================= Percent change 17.5% (1.1)% -----------------------------------------------------------------
Retail revenues increased 16.7 percent or $40.4 million in 2000 as compared to 1999. The primary contributors to the increase were continued growth in the Company's service territory, the positive impact of weather on energy sales, and an increase in fuel revenues.
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. The Company currently plans to make a filing with the Georgia Public Service Commission (GPSC) in early 2001 to establish a new fuel rate in order to better reflect current fuel cost and to collect the current under-recovered balance.
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Revenues from these sales were not material to the financial statements.
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 2000 and the percent change by year were as follows:
KWH Percent Change ------------- ------------------- 2000 2000 1999 ------------- ------------------- (in millions) Residential 1,671 5.8% 2.6% Commercial 1,369 6.3 4.2 Industrial 800 12.2 (20.7) Other 137 2.5 1.1 ------- Total retail 3,977 7.1 (2.5) Sales for resale -- Non-affiliates 77 50.3 (3.3) Affiliates 89 15.1 31.8 -------- Total 4,143 7.8% (2.0)% ===========================================================
Total retail energy sales in 2000 reflected increases in all customer classes. Industrial energy sales increased 12.2 percent reflecting the re-opening of an industrial facility under new ownership. Residential and commercial sales also increased reflecting weather related demand and customer growth.
In 1999, total retail energy sales were down by 2.5 percent from the prior year reflecting reduced energy sales of 20.7 percent to industrial customers due to the shut-down of one industrial customer's facilities in late 1998 and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2000 Annual Report
completed construction of a steam turbine unit by another industrial customer. These reductions were partially mitigated by increased energy sales of 2.6 percent and 4.2 percent to residential and commercial customers, respectively.
Expenses
Total operating expenses for 2000 were $245.0 million, an increase of $42.0 million from the prior year due primarily to increases in purchased power from both affiliates and non-affiliates and generation fuel expense. The increase in fuel expense is attributable to an increase in generation and higher fuel costs. 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.
In 1999, total operating expenses were $203.0 million reflecting a slight increase of $1.4 million from the prior year. This increase was due primarily to increases in purchased power from non-affiliates and depreciation and amortization. Purchased power from non-affiliates increased due principally to higher demand for energy and increased costs associated with these power purchases. Depreciation and amortization increased reflecting additional depreciation charges related to the GPSC's 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:
2000 1999 1998 -------------------------- Total energy supply (millions of KWHs) 4,286 4,039 4,182 Sources of energy supply (percent) -- Coal 52 45 42 Oil 2 2 1 Gas 5 10 12 Purchased Power 41 43 45 Total average cost of energy supply (cents) 3.09 2.44 2.35 - -----------------------------------------------------------------
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
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.
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).
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2000 Annual Report
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.
Georgia Power 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 capacity from these units to serve its retail customers for approximately seven years.
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. The Company is positioning the business to meet the challenge of this major change in the traditional practice of selling electricity.
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. As these initiatives materialize, the structure of the utility industry could radically change. 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 transmission pricing and recovery of costs. The GPSC continues its assessment of the range of potential stranded costs. The inability of the Company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on the financial condition and results of operation. The Company is attempting to minimize or reduce its cost exposure.
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.
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 issued a four-year accounting order settling its review of the Company's earnings. See Note 3 to the financial statements for additional information.
On December 20, 1999, FERC issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. After participating in regional conferences with customers and other members of the public to discuss the formation of RTOs, utilities were required to make a filing. On October 16, 2000, Southern Company and its integrated utility subsidiaries, including the Company, filed with FERC a proposal for the creation of an RTO. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of Southern Company and any other participating utilities. Participants would have the option to maintain their ownership, divest, sell, or lease their assets to the proposed RTO. If the FERC accepts the proposal as filed, the creation of an RTO is not expected to have a material impact on Southern Company's financial statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUCHA) to allow holding companies to form exempt wholesale generators to sell power largely free of regulation under PUCHA. These entities are able to own and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2000 Annual Report
operate power generating facilities and sell power to affiliates--under certain restrictions.
Southern Company is aggressively working to maintain and expand its share of wholesale sales in the southeastern power markets. In January 2001, Southern Company announced formation of a new subsidiary--Southern Power Company. The new subsidiary will own, manage, and finance wholesale generating assets in the Southeast. Energy from its assets will be marketed to wholesale customers under the Southern Company name.
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."
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 Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. Statement No. 133 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 Company enters into commodity related forward contracts to limit exposure to changing prices on electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales meet the definition of a derivative under Statement No. 133. In many cases, these transactions meet the normal purchase and sale exception and the related contracts will continue to be accounted for under the accrual method. Certain of these instruments qualify as cash flow hedges resulting in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness will be recognized currently in net income. However, others will be required to be marked to market through current period income.
The Company adopted Statement No. 133 effective January 1, 2001. The impact on net income was immaterial to the Company. The application of the new rules is still evolving and further guidance from FASB is expected, which could further impact the Company's financial statements. Also, as wholesale energy markets mature, future transactions could result in more volatility in net income and comprehensive income.
FINANCIAL CONDITION - ------------------
Overview
The principal change in the Company's financial condition in 2000 was the addition of $27.3 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.
Exposure to Market Risks
Due to cost-based regulation, the Company has limited exposure to market volatility in interest rate, 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, 2000, exposure from these activities was not material to the Company's financial statements. Also, based on the Company's overall interest rate exposure at December 31, 2000, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2000 Annual Report
Capital Structure
As of December 31, 2000, the Company's capital structure consisted of 52.7 percent common stockholders' equity, 12.1 percent trust preferred securities, and 35.2 percent long-term debt, excluding amounts due within one year. The Company's long-term financial objective for capitalization ratios is to maintain a capital structure of common stockholders' equity at 48 percent, preferred securities at 10 percent and debt at 42 percent.
Maturities and retirements of long-term debt were $0.4 million in 2000, $16.2 million in 1999, and $30.4 million in 1998.
Included in the 1999 maturities and retirements is the purchase by the Company of all $15 million outstanding of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.
The composite interest rates and dividend rates for the years 1998 through 2000 as of year-end were as follows:
2000 1999 1998 ------------------------------- Composite interest rates on long-term debt 6.6% 6.4% 6.5% 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 $95.9 million ($32.5 million in 2001, $31.5 million in 2002, and $31.9 million in 2003). Actual construction costs may vary from this estimate because of 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 $51.8 million will be needed by the end of 2003 for maturities of long-term debt and present sinking fund requirements.
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 integrated Southeast utilities 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 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 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 the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. The EPA did not include the system service company in the new complaint. Southern Company believes that its integrated utilities 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2000 Annual Report
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 and some 50 generating units of Southern Company were brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. The construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $2 million for Savannah Electric.
Phase II sulfur dioxide compliance was required in 2000. Southern Company used emission allowances and fuel switching to comply with Phase II requirements. No significant dollars for Phase II compliance have been spent by Savannah Electric.
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 recently dismissed certain challenges but 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 will address other legal challenges to these standards in mid-2001. If the standards are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May 31, 2004. The final rule affects 21 states, including Georgia. This rule remains involved in litigation in the federal courts.
In December 2000, the EPA completed its utility studies 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 (MACT) provisions of the Clean Air Act. This determination is being challenged in the courts. 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 BART rules is probable in the near future.
Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C. add to the uncertainties associated with BART guidance and the MACT determination for mercury and other HAPS.
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; 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2000 Annual Report
The Company conducts studies to determine the extent of any required cleanup costs 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, 2000, the Company had $50.1 million of unused 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.
It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulation, 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.
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," "expects," "plans," "anticipates," "believes," "estimates," "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 against the Company; the extent and timing of the entry of additional competition in the markets of the Company; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; internal restructuring or other restructuring options that may be pursued by the Company; state and federal rate regulation in the United States; political, legal and economic conditions and developments in the United States; financial market conditions and the results of financing efforts; the impact of fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
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NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 2000 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 integrated Southeast utilities, a system service company (SCS), Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern Nuclear), Mirant Corporation--formerly Southern Energy, Inc.--and other direct and indirect subsidiaries. The integrated Southeast utilities provide electric service in four states. Contracts among the integrated Southeast utilities--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 integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Mirant acquires, develops, builds, owns and operates power production and delivery facilities, and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Mirant businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
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.
Related-Party 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 administrative services with respect to business and operations and power pool operations. Costs for these services amounted to $15.1 million, $16.0 million, and $15.3 million during 2000, 1999, and 1998, 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:
2000 1999 -------------------------- (in thousands) Deferred income tax charges $12,404 $ 16,063 Premium on reacquired debt 7,575 8,385 Deferred income tax credits (16,038) (19,687) Storm damage reserves (2,733) (1,392) Accelerated depreciation (5,500) (3,000) - --------------------------------------------------------------- Total $(4,292) $ 369 ===============================================================
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.
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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.
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 2000, the GPSC approved an increase of slightly over one-third of a cent per kilowatt hour in the Company's fuel cost recovery rate. An increase of slightly over three-tenths of a cent per kilowatt-hour was approved in 1999.
The Company currently plans to make a filing with the GPSC in early 2001 to establish a new fuel rate in order to better reflect current fuel costs and to collect the current under-recovered balance.
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 2000 and 1999, and 2.9 percent in 1998. 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 1998, 1999 and 2000, the Company recorded accelerated depreciation of $1.0 million, $2.0 million and $2.5 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, which is included in the consolidated federal income tax return filed by 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.
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 6.87 percent in 2000, 6.26 percent in 1999 and 8.00 percent in 1998.
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 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
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when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Financial Instruments
The Company's 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, 2000 $142 $140 At December 31, 1999 $142 $136 Trust preferred securities: At December 31, 2000 $40 $36 At December 31, 1999 $40 $31
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. Substantially all these employees may become eligible for such benefits when they retire. The Company funds trusts to the extent required by the GPSC. 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. The effects of these changes will be to increase annual pension and postretirement benefits costs by approximately $0.5 million and $0.3 million, respectively.
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 --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $59,961 $59,207 Service cost 1,742 1,746 Interest cost 4,380 3,893 Benefits paid (3,210) (3,414) Actuarial (gain) loss and employee transfers 1,802 (1,856) Amendments 219 385 - --------------------------------------------------------------- Balance at end of year $64,894 $59,961 ===============================================================
Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $54,480 $49,630 Actual return on plan assets 10,493 8,168 Benefits paid (3,210) (3,414) Employee transfers 117 96 - --------------------------------------------------------------- Balance at end of year $61,880 $54,480 ===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in thousands) Funded status $(3,014) $(5,481) Unrecognized transition obligation 89 178 Unrecognized prior service 2,929 2,996 cost Unrecognized net loss (gain) (1,127) 3,508 - --------------------------------------------------------------- (Accrued liability) prepaid asset recognized in the Balance Sheets $(1,123) $1,201 ===============================================================
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Components of the plans' net periodic cost were as follows:
2000 1999 1998 - ----------------------------------------------------------------- (in thousands) Service cost $1,742 $1,746 $1,495 Interest cost 4,380 3,893 3,806 Expected return on plan assets (4,174) (4,063) (3,992) Recognized net loss - 152 2 Net amortization 376 352 334 - ----------------------------------------------------------------- Net pension cost $2,324 $2,080 $1,645 =================================================================
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 --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $22,904 $23,556 Service cost 376 404 Interest cost 1,865 1,549 Benefits paid (963) (756) Actuarial gain and employee transfers (1,367) (1,849) Amendments 3,309 - - --------------------------------------------------------------- Balance at end of year $26,124 $22,904 ===============================================================
Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $5,254 $3,803 Actual return on plan assets 606 476 Employer contributions 2,013 1,731 Benefits paid (963) (756) - --------------------------------------------------------------- Balance at end of year $6,910 $5,254 ===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2000 1999 - --------------------------------------------------------------- (in thousands) Funded status $(19,214) $(17,650) Unrecognized transition obligation 5,925 6,419 Unamortized prior service cost 3,185 - Unrecognized net loss 1,701 3,311 Fourth quarter contributions 1,493 1,336 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (6,910) $ (6,584) ===============================================================
Components of the postretirement plans' net periodic cost were as follows:
2000 1999 1998 - ---------------------------------------------------------------- (in thousands) Service cost $ 376 $ 404 $ 348
Interest cost 1,865 1,549 1,528 Expected return on plan assets (429) (345) (276) Recognized net loss 66 152 104 Net amortization 618 494 494 - ---------------------------------------------------------------- Net postretirement cost $2,496 $2,254 $2,198 ================================================================
The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were:
2000 1999 - --------------------------------------------------------------- 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 7.29 percent for 2000, decreasing gradually to 5.50 percent through the year 2005, 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, 2000 as follows:
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1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in thousands) Benefit obligation $1,417 $1,598 Service and interest costs 110 140 ===============================================================
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 2000, 1999, and 1998 were $0.9 million, $0.9 million, and $0.8 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
Environmental Litigation
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 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, 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 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 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 the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. The EPA did not include the system service company in the new complaint. Southern Company believes that its integrated utilities 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
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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 in both 2000 and 1999 and $0.75 million in 1998. 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.
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated to total $32.5 million in 2001, $31.5 million in 2002, and $31.9 million in 2003. 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.
To the extent possible, the Company's construction program is expected to be financed from internal sources and from the issuance of additional long-term debt and capital contributions from Southern Company.
The amounts of long-term debt and trust preferred securities that can be issued in the future will be contingent on market conditions, the maintenance of adequate earnings levels, regulatory authorizations, and other factors.
Bank Credit Arrangements
At the end of 2000, unused credit arrangements with four banks totaled $50.1 million and expire at various times during 2001.
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.
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 $10 million of bank debt is secured by a portion of the Plant Kraft property and a second lien for $34 million in bank notes is secured by a portion of the Plant McIntosh property.
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 $44 million and $8 million for 2001 and 2002, respectively.
The company has entered into various long-term commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2000 were as follows:
Year Commitments - ---- ------------- (in thousands) 2001 $ 0 2002 9,627 2003 13,245 2004 13,261 2005 13,277 2006 and beyond 53,283 - --------------------------------------------------------------- Total commitments $102,693 ===============================================================
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Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.4 million for 2000, $0.5 million for 1999, and $1.1 million for 1998.
At December 31, 2000, estimated future minimum lease payments for noncancelable operating leases were as follows:
Rental Commitments -------------------- (in thousands) 2001 $433 2002 433 2003 433 2004 433 2005 433 2006 and thereafter $5,379 - -------------------------------------------------------------
5. INCOME TAXES
At December 31, 2000, tax-related regulatory assets and liabilities were $12.4 million and $16.0 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:
2000 1999 1998 - ------------------------------------------------------------------ (in thousands) Total provision for income taxes Federal -- Currently payable $11,102 $12,968 $ 6,763 Deferred 75 (3,329) 5,812 - ------------------------------------------------------------------ 11,177 9,639 12,575 - ------------------------------------------------------------------ State -- Currently payable 1,744 2,193 1,327 Deferred 653 (24) 1,199 - ------------------------------------------------------------------ 2,397 2,169 2,526 - ----------------------------------------------------------------- Total $13,574 $11,808 $15,101 ==================================================================
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:
2000 1999 -------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $76,901 $76,282 Property basis differences 5,904 6,917 Other 17,807 12,031 - ---------------------------------------------------------------- Total 100,612 95,230 - ---------------------------------------------------------------- Deferred tax assets: Pension and other benefits 9,744 6,965 Other 7,662 5,777 - ---------------------------------------------------------------- Total 17,406 12,742 - ---------------------------------------------------------------- Net deferred tax liabilities 83,206 82,488 Portions included in current assets, net (3,450) (2,170) - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $79,756 $80,318 ================================================================
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 $ 0.7 million in 2000, 1999 and 1998. At December 31, 2000, 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:
2000 1999 1998 ----------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of federal income tax benefit 4 4 4 Other (2) (5) (2) ---------------------------------------------------------------- Effective income tax rate 37% 34% 37% ================================================================
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.
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6. 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.
7. LONG-TERM DEBT AND LONG-TERM DEBT DUE WITHIN ONE YEAR
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 $0.4 million in 2000, $16.2 million in 1999 and $30.4 million in 1998. Included in the 1999 maturities and retirements is the purchase by the Company of all $15 million outstanding of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.
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.
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:
2000 1999 --------------------- (in thousands) Bond sinking fund requirement $ 642 $650 Less: Portion to be satisfied by certifying property additions 642 650 - ------------------------------------------------------------------- Cash sinking fund requirement - - Other long-term debt maturities 30,698 704 - ------------------------------------------------------------------- Total $30,698 $704 ===================================================================
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 certifying property additions in 2000 and by cash redemptions in 1999. It is anticipated that the 2001 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2005 applicable to long-term debt are as follows: $30.7 million in 2001; $0.6 million in 2002; $20.5 million in 2003; $0.5 million in 2004; and $0.4 million in 2005.
8. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Indenture contains certain limitations on the payment of cash dividends on common stock. At December 31, 2000, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Indenture.
II-192
NOTES (continued) Savannah Electric and Power Company 2000 Annual Report
9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2000 and 1999 are as follows (in thousands):
Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock - ---------------------------------------------------------------------
March 2000 $52,390 $ 6,583 $ 1,643 June 2000 72,780 14,100 6,287 September 2000 98,849 24,060 12,351 December 2000 71,699 5,939 2,688
March 1999 $47,098 $ 5,315 $ 1,209 June 1999 61,692 12,173 5,268 September 1999 91,849 26,759 13,705 December 1999 50,955 4,355 2,901 - ---------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
The quarterly operating income information above has been reclassified to reflect the Company's current presentation of income tax expense.
11-193
II-194
II-195
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 2001 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 2001 Annual Meetings of Shareholders.
The ages of directors and executive officers in Item 10
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Identification of directors of SAVANNAH.
G. Edison Holland, Jr. President and Chief Executive Officer Age 48 Served as Director since 7-15-97
Gus H. Bell (1) Age 63 Served as Director since 7-20-99
Archie H. Davis (1) Age 59 Served as Director since 2-18-97
Walter D. Gnann (1) Age 65 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 55 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 64 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 17, 2000) for one year until the next annual meeting or until a successor is elected and qualified.
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 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.
G. Edison Holland, Jr. President, Chief Executive Officer and Director Age 48 Served as Executive Officer since 7-15-97
Anthony R. James Vice President - Power Generation Age 50 Served as Executive Officer since 7-27-00
W. Miles Greer Vice President - Customer Operations and External Affairs Age 57 Served as Executive Officer since 11-20-85
Kirby R. Willis Vice President, Treasurer, Chief Financial Officer and Assistant Corporate Secretary Age 49 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 27, 2000 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 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.
III-1
Family relationships. None.
Business experience.
G. Edison Holland, Jr. - President and Chief Executive Officer since 1997. He previously served as Vice President of Power Generation/Transmission and Corporate Counsel of GULF from 1995 to 1997. Served as a partner in the law firm of Beggs & Lane from 1979 to 1997. 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 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 - 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.
Anthony R. James - Vice President - Power Generation and Senior Production Officer since 2000. He also serves as Central Cluster Manager at GEORGIA's Plant Scherer. 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 effective 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.
Item 11. EXECUTIVE COMPENSATION
Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the four most highly compensated executive officers of SAVANNAH serving during 2000.
1 Tax reimbursement by SAVANNAH on certain personal benefits, including membership fees of $11,669 for Mr. Holland, Jr. in 1998. 2 Payouts made in 1999 and 2000 for the four-year performance periods ending December 31, 1998 and 1999, respectively. 3 SAVANNAH contributions 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:
4 Mr. James was named an executive officer effective July 27, 2000. 5 Mr. Jeffers was named an executive officer of SAVANNAH effective November 2, 1999 and transferred to ALABAMA effective June 24, 2000.
III-3
STOCK OPTION GRANTS IN 2000
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, 2000.
6 Performance Stock Plan grants were made on February 18, 2000, 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 fair market value of SOUTHERN's common stock on the date granted. Options may be transferred to family members, family trusts, and family limited partnerships. 7 A total of 6,977,038 stock options were granted in 2000. 8 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:
III-4
AGGREGATED STOCK OPTION EXERCISES IN 2000 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information concerning options exercised during the year ending December 31, 2000 by the named executive officers and the value of unexercised options held by them as of December 31, 2000.
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 Messrs. Holland, James and Jeffers. Compensation for pension purposes is limited to the average of the highest three of the final 10 years' compensation -- base salary plus the excess of annual and long-term incentive compensation over 25 percent of base salary (reported under column titled "Salary", "Bonus", and "Long-Term Incentive Payouts" in the Summary Compensation Table on page III-3).
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 (although married employees are required to have their pension benefits paid in one of various joint and survivor annuity forms, unless the employee elects otherwise with the spouse's consent) or computation of the Social Security offset which would apply in most cases. This offset amounts to one-half of the estimated Social Security benefit (primary insurance amount) in excess of $3,900 per year times the number of years of accredited service, divided by the total possible years of accredited service to normal retirement age.
As of December 31, 2000, the applicable compensation levels and years of accredited service for SAVANNAH's named executives are presented in the following table:
Compensation Accredited Name Level Years of Service
G. Edison Holland, Jr.9 $431,348 17 Anthony R. James 246,604 21 W. Miles Greer10 237,392 16 Kirby R. Willis 225,952 26 Lewis A. Jeffers 197,400 21
9 The number of accredited years of service includes 9 years and 3 months credited to Mr. Holland pursuant to a supplemental pension agreement.
10 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 2000 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 2000 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 per quarter
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 the respective companies' 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, 2000 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 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.
If a change in control affects only a subsidiary of SOUTHERN, these payments would only be made to executives of the affected subsidiary who are involuntarily terminated as a result of that change in control.
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.
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.
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, 2000. 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, 2000.
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2) - ------------------ -------------- --------------------------
Gus H. Bell, III SOUTHERN Common 246 Archie H. Davis SOUTHERN Common 495 Walter D. Gnann SOUTHERN Common 2,689 G. Edison Holland, Jr. SOUTHERN Common 43,848 Robert B. Miller, III SOUTHERN Common 1,770 Arnold M. Tenenbaum SOUTHERN Common 1,124 Anthony R. James SOUTHERN Common 25,065 W. Miles Greer SOUTHERN Common 18,605 Kirby R. Willis SOUTHERN Common 23,240
The directors, nominees and executive officers as a group SOUTHERN Common 117,083
(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, 14,707 shares; Mr. Holland, 40,817 shares; Mr. James 12,707 shares, and Mr. Willis, 16,503 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Transactions with management and others.
Mr. Archie Davis is President of The Savannah Bank, N.A., Savannah, Georgia. During 2000, 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.
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 2000 were as follows:
SOUTHERN filed Current Reports on Form 8-K:
Date of event: November 27, 2000 Items reported: Items 5 and 7
Date of event: December 6, 2000 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, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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 President and Chief Executive Officer (Principal Executive Officer)
Gale E. Klappa Financial Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
W. Dean Hudson Vice President, 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 H. Allen Franklin Gerald J. St. Pe'
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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: Elmer B. Harris, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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.
Elmer B. Harris 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 John T. Porter H. Allen Franklin Robert D. Powers R. Kent Henslee Andreas Renschler Carl E. Jones, Jr. C. Dowd Ritter James K. Lowder James H. Sanford Wallace D. Malone, Jr. John Cox Webb, IV Thomas C. Meredith James W. Wright William V. Muse
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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 28, 2001
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: Daniel P. Amos James R. Lientz, Jr. Juanita P. Baranco G. Joseph Prendergast William A. Fickling, Jr. William Jerry Vereen H. Allen Franklin Carl Ware L. G. Hardman III E. Jenner Wood, III
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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 Comptroller and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Fred C. Donovan, Sr. W. Deck Hull, Jr. H. Allen Franklin Barbara H. Thames
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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: Dwight H. Evans, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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.
Dwight H. Evans President, Chief Executive Officer and Director (Principal Executive Officer)
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Robert S. Gaddis George A. Schloegel Linda T. Howard Philip J. Terrell Aubrey K. Lucas Gene Warr Malcolm Portera
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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: G. Edison Holland, Jr., President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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.
G. Edison Holland, Jr. 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
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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 L.P. Holdings Corp. Georgia Georgia Power Capital, L.P. 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 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
- ----------------------------------------------------- -- ---------------------
*This information is as of December 31, 2000. In addition, the list omits certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K Item 601.
IV-5
ARTHUR ANDERSEN LLP
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 28, 2001 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, 33-30171, 33-54415, 33-57951, 33-58371, 33-60427, 333-09077, 333-44127, 333-44261, 333-64871 and 333-31808.
/s/ Arthur Andersen LLP Atlanta, Georgia March 22, 2001
IV-6
ARTHUR ANDERSEN LLP
Exhibit 23(b)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 28, 2001 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. 333-67453.
/s/ Arthur Andersen LLP Birmingham, Alabama March 22, 2001
IV-7
Exhibit 23(c)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 28, 2001 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 No. 333-75193.
/s/ Arthur Andersen LLP Atlanta, Georgia March 22, 2001
IV-8
Exhibit 23(d) ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 28, 2001 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 Nos. 33-50165 and 333-42033.
/s/ Arthur Andersen LLP Atlanta, Georgia March 22, 2001
IV-9
ARTHUR ANDERSEN LLP Exhibit 23(e)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 28, 2001 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 22, 2001
IV-10
ARTHUR ANDERSEN LLP Exhibit 23(f)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 28, 2001 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. 333-46171.
/s/ Arthur Andersen LLP Atlanta, Georgia March 22, 2001
IV-11
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-12
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-13
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-14
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-15
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-16
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves 2000, 1999 and 1998 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
S-2
S-3
S-4
S-5
S-6
S-7