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. ALABAMA and GEORGIA each own 50% of the outstanding common stock of SEGCO. The operating affiliates supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively, and SEGCO owns generating units at a large electric generating station which supplies power to ALABAMA and GEORGIA. More particular information relating to each of the operating affiliates 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 Energy, Southern LINC, Southern Nuclear, SCS (the system service company), Energy Solutions and other direct and indirect subsidiaries. Southern Energy is focused on several key international and domestic business lines, including energy distribution, integrated utilities, stand-alone generation, and other energy-related products and services. A further description of Southern Energy's business and organization follows later in this section under "Non-Traditional Business." Southern LINC provides digital wireless communications services to SOUTHERN's operating affiliates and also markets these services to the public within the Southeast. Southern Nuclear provides services to the Southern electric system's nuclear plants. Energy Solutions develops new business opportunities related to energy products and services.
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.
The SOUTHERN System
Traditional Business
The transmission facilities of each of the operating affiliates and SEGCO are connected to the respective company's own generating plants and other sources of power and are interconnected with the transmission facilities of the other operating affiliates 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 Operating Affiliates" herein.)
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Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. Additionally, the operating affiliates have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy Corporation, South Carolina Electric & Gas Company and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The operating affiliates have joined with other utilities in the Southeast (including those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the operating affiliates are represented on the National Electric Reliability Council.
An intra-system interchange agreement provides for coordinating operations of the power producing facilities of the operating affiliates and SEGCO and the capacities available to such companies from non-affiliated sources and for the pooling of surplus energy available for interchange. Coordinated operation of the entire interconnected system is conducted through a central power supply coordination office maintained by SCS. The available sources of energy are allocated to the operating affiliates to provide the most economical sources of power consistent with good operation. The resulting benefits and savings are apportioned among the operating affiliates.
SCS has contracted with SOUTHERN, each operating affiliate, Southern Energy, 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. Southern Energy, Energy Solutions and Southern LINC have also secured from the operating affiliates 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.
Non-Traditional Business
SOUTHERN continues to consider new business opportunities, particularly those which allow use of the expertise and resources developed through its regulated utility experience. These endeavors began in 1981 and are conducted through Southern Energy and other subsidiaries. SOUTHERN has filed with the SEC an application for authority to invest up to nearly $8 billion in the non-traditional domestic and international business. A consumer group has filed a motion to intervene in this proceeding. The current SEC authority is $3.9 billion, of which $3.6 billion has been invested as of December 31, 1998.
Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. As the energy marketplace evolves, Southern Energy continues to position SOUTHERN to become a major competitor. During 1998, Southern Energy further refined its business strategy to focus on a few geographic regions of the world. In Asia, Southern Energy will focus primarily on China, the Philippines and India. In South America, Southern Energy will pursue opportunities in Brazil. In Europe, Southern Energy will concentrate efforts on the European Union countries. And in North America, Southern Energy will target efforts in Northeast, the Midwest, Texas and California. See Item 7 for SOUTHERN's Management's Discussion and Analysis under the heading "Future Earnings Potential" for additional information regarding this strategy.
Reference is also made to Note 14 to the financial statements of SOUTHERN in Item 8 herein for additional information regarding SOUTHERN's segment and related information.
In 1995, SOUTHERN, through its subsidiary Southern Energy, acquired SWEB, one of the United Kingdom's 12 regional electric distribution companies, for approximately $1.8 billion. In July 1996, a 25 percent interest in SWEB was sold to PP&L Resources.
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In June 1998, SOUTHERN through its subsidiary Southern Energy sold an additional 26% interest in SWEB to PP&L Resources for $170 million. SWEB is, to a limited extent, involved in power generation and certain non-regulated activities which include gas marketing and telecommunications. In mid-1997, the acquisition of CEPA was completed for a total net investment of $2.1 billion. CEPA is engaged in the business of developing, constructing, owning and operating electric power generation facilities. Its current operations include installed operating capacity of approximately 3,306 megawatts, with projects either completed or under development in the Philippines, the People's Republic of China, and India. (For additional information related to the acquisition of CEPA, reference is made to Note 13 to SOUTHERN's financial statements in Item 8 herein.) In 1997, Southern Energy also acquired a 26% interest in a German utility for approximately $820 million.
In January 1998, Southern Energy entered into a joint venture with Vastar Resources, Inc. The two companies combined their energy trading and marketing operations to form a new full-service energy provider, Southern Company Energy Marketing. The joint venture agreement gives Southern Company Energy Marketing rights to market virtually all of Vastar's natural gas production over the next 10 years.
In December 1998, Southern Energy completed its $537 million purchase of 1,267 megawatts of generating capacity from Commonwealth Electric. In addition, Southern Energy plans to add 685 megawatts of capacity at the plants. In late 1998, Southern Energy announced the $801 million planned acquisition of 3,065 megawatts of generating capacity from Pacific Gas & Electric in northern California. Additionally, Southern Energy announced plans to acquire from Orange and Rockland Utilities Inc. and Consolidated Edison Inc. in New York 1,776 megawatts of capacity for $480 million. These transactions are expected to close during 1999. Further, Southern Energy has announced plans to build or purchase an additional 980 megawatts of capacity in Texas and Wisconsin. Through Southern Company Energy Marketing, Southern Energy has also gained access to additional capacity through marketing agreements. Southern Energy additionally has access to almost 2,000 megawatts of capacity through marketing agreements with Sithe Energies in New York and Brazos Electric Cooperative in Texas.
After refining its international focus and reviewing the financial performance of existing assets, Southern Energy announced plans to sell its holdings in Edelnor in Chile and Alicura in Argentina. As a result, Southern Energy recorded a write down of $200 million, after taxes, in December 1998 related to these holdings. Because of regulatory and market conditions, these assets did not meet expectations.
In January 1999, Mobile Energy, an indirect subsidiary of SOUTHERN, and its direct parent filed petitions for Chapter 11 bankruptcy relief in the U.S. Bankruptcy Court for the Southern District of Alabama. For additional information regarding this matter, reference is made to Item 3 - LEGAL PROCEEDINGS herein.
See Item 2
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1998, operated 33 hydroelectric generating stations, 33 fossil fuel generating stations and three nuclear generating 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 Chickasaw Chickasaw, AL 40,000 Greene County Demopolis, AL 300,000 (2) Gaston Unit 5 Wilsonville, AL 880,000 Miller Birmingham, AL 2,532,288 (3) --------- ALABAMA Total 6,618,538 ---------
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 -----------
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------------------------- ----------------------------------------- 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 21,700,243 -----------
Nuclear Steam Farley Dothan, AL ALABAMA Total 1,720,000 ----------- Hatch Baxley, GA 862,669 (8) Vogtle Augusta, GA 1,060,240 (9) ----------- GEORGIA Total 1,922,909 ---------- Total Nuclear Steam 3,642,909 -----------
Combustion Turbines Greene County Demopolis, AL
ALABAMA Total 720,000
Arkwright Macon, GA 30,580 Atkinson Atlanta, GA 78,720 Bowen Cartersville, GA 39,400 Intercession City Intercession City, FL 47,333 (10) McDonough Atlanta, GA 78,800 McIntosh Units 1,2,3,4,7,8 Effingham County, GA 480,000 McManus Brunswick, GA 481,700 Mitchell Albany, GA 118,200 Robins Warner Robins, GA 160,000 Wilson Augusta, GA 354,100 Wansley Carrollton, GA 26,322 (5) ----------- GEORGIA Total 1,895,155 ---------
Lansing Smith Unit A Panama City, FL 39,400 Pea Ridge Units 1-3 Pea Ridge, FL 14,250 GULF Total 53,650
Chevron Cogenerating Station Pascagoula, MS 147,292 (11) Sweatt Meridian, MS 39,400 Watson Gulfport, MS 39,360 --------- MISSISSIPPI Total 226,052 ---------
------------------------------------------------- -----------------
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--------------------------- -------------------- ----------------- Nameplate Generating Station Location Capacity --------------------------- -------------------- ----------------- (Kilowatts) Boulevard Savannah, GA 59,100 Kraft Port Wentworth, GA 22,000 McIntosh Units 5&6 Effingham County, 160,000 ------- GA SAVANNAH Total 241,100 241,100
Gaston (SEGCO) Wilsonville, AL 19,680 (7) Total Combustion Turbines 3,155,637
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 58,000 Lewis Smith Jasper, AL 157,500 Bankhead Holt, AL 45,125 Holt Holt, AL 40,000 ----------- ALABAMA Total 1,582,725 ----------
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 2,660,461 -----------
Total Generating Capacity 31,159,250
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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.
Except as discussed below under "Titles to Property," the principal plants and other important units of the operating affiliates 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, 1998, the unamortized portion of this cost was $37 million.
The all-time maximum demand on the operating affiliates and SEGCO was 28,933,700 kilowatts and occurred in June 1998. This amount excludes demand served by capacity retained by MEAG and Dalton and excludes demand associated
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with power purchased from OPC and SEPA by its preference customers. The reserve margin for the operating affiliates and SEGCO at that time was 12.8%. 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.)
Other Electric Generation Facilities
Through special purpose subsidiaries, SOUTHERN owns interests in or operates independent power production facilities and foreign utility companies. The generating capacity of these utilities (or facilities) at December 31, 1998, was as follows:
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 connection with the joint ownership arrangements for Plant Vogtle, GEORGIA made commitments to purchase portions of OPC's and MEAG's capacity and energy from this plant. Declining commitments were in effect during periods of up to seven years following commercial operation and ended in 1996. In addition, the Company 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.
In December 1988, GEORGIA and OPC entered into a joint ownership agreement for the Rocky Mountain plant under which GEORGIA agreed to retain its present investment in the project and OPC agreed to finance, complete and operate the facility. In 1995, the plant went into commercial operation. GEORGIA's ownership
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is 25.4 percent. On January 14, 1998, the GPSC ordered that the Company be allowed approximately $108 million of its $142 million investment in the plant in rate base as of December 31, 1998. GEORGIA appealed the GPSC's order. Under the rate order approved by the GPSC on December 18, 1998, GEORGIA voluntarily dismissed the appeal. As a result, in December 1998, GEORGIA recorded a charge to earnings of $21 million, after taxes, associated with the write-down of the plant. Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for additional information regarding the Rocky Mountain plant.
In 1994, GEORGIA and FPC entered into a joint ownership agreement regarding the Intercession City combustion turbine unit. The unit began commercial operation in January 1997, and is operated by FPC. GEORGIA owns a one-third interest in the unit, with use of 100% of the capacity from June through September. FPC has the capacity the remainder of the year.
Titles to Property
The operating affiliates' 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 operating affiliates 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.
Property Additions and Retirements
During the period from January 1, 1994 to December 31, 1998, the operating affiliates, SEGCO, SCS, Southern Nuclear, Southern LINC and Southern Energy recorded gross property additions and retirements as follows:
------------------------- ------------------- --- ---------- Gross Property Additions Retirements --------------- ------------- (in millions)
ALABAMA $2,576 $ 426 GEORGIA (1) 2,522 1,263 GULF 327 131 MISSISSIPPI 357 98 SAVANNAH 122 13 SEGCO 27 8 SCS 108 171 Southern Nuclear 4 6 Southern LINC 300 48 Southern Energy 1,677 54 Other 10 - ============================ =========== == ================ SOUTHERN system $8,030 $2,218 ============================ =========== == ================
Notes: (1) Includes approximately $229 million attributable to sales of Plant Scherer Unit 4 to FP&L and JEA.
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Item 3.
Item 3. LEGAL PROCEEDINGS
(1) Frost v. ALABAMA
(Circuit Court of Jefferson County, Alabama)
Reference is made to Note 3 to SOUTHERN's and ALABAMA's financial statements in Item 8 herein under the captions "Alabama Power Appliance Warranty Litigation" and "Appliance Warranty Litigation", respectively.
(2) Sullivan v. ALABAMA et al. (Circuit Court of Jefferson County, Alabama)
Reference is made to Note 3 to SOUTHERN's and ALABAMA's financial statements in Item 8 herein under the captions "Alabama Power Environmental Litigation" and "Environmental Litigation", respectively.
(3) 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 "Certain Environmental Contingencies," respectively.
(4) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy Services Holdings, Inc. (U.S. Bankruptcy Court for the Southern District of Alabama).
In January 1999, Mobile Energy, an indirect subsidiary of SOUTHERN, and its direct parent filed petitions for Chapter 11 bankruptcy relief in the U.S. Bankruptcy Court for the Southern District of Alabama. For additional information regarding this matter, reference is made to Note 3 to SOUTHERN's financial statements in Item 8 herein. In March 1999, SOUTHERN paid a total of approximately $36 million in respect of guaranty and reimbursement agreements previously entered into by it for the benefit of Mobile Energy creditors.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation - - - - - - - - Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's financial statements in Item 8 herein for a description of certain other administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, Southern Energy, 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.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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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, 1998.
A. W. Dahlberg Chairman, President and Chief Executive Officer Age 58 Elected Director in 1985, President effective January 1994, and Chairman and Chief Executive Officer effective March 1995.
Paul J. DeNicola Executive Vice President and Director Age 50 Elected Director in 1989 and Executive Vice President of SOUTHERN in 1991. He also has served as President and Chief Executive Officer of SCS since January 1994.
H. Allen Franklin Executive Vice President and Director Age 54 Elected Director in 1988 and Executive Vice President in 1991. He also has served as President and Chief Executive Officer of GEORGIA since January 1994.
Elmer B. Harris Executive Vice President and Director Age 59 Elected Director in 1989, and Executive Vice President in 1991. He also has served as President and Chief Executive Officer of ALABAMA since 1989.
Thomas G. Boren Senior Vice President Age 49 Elected in 1995. He also has served as President and Chief Executive Officer of Southern Energy since 1992.
Stephen A. Wakefield Senior Vice President and General Counsel Age 58 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.
W. L. Westbrook Financial Vice President, Chief Financial Officer and Treasurer Age 59 Elected in 1986; responsible primarily for all aspects of financing for SOUTHERN. He also has served as Executive Vice President of SCS since 1986.
C. Alan Martin Vice President Age 50 Elected in 1998; serves as Chief Marketing Officer for the SOUTHERN system. Previously Vice President of Human Resources of SOUTHERN from 1995 to February 1998, and Vice President of ALABAMA from 1987 to 1995.
Charles D. McCrary Vice President Age 47 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 and Executive Vice President of ALABAMA since 1994. Previously served as Senior Vice President of ALABAMA from 1991 to 1994.
W. G. Hairston, III Age 53 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 27, 1998) for one year until the next annual meeting or until their successors are elected and have qualified.
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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 $28-11/16 $23-15/16 Second Quarter 29 25-1/16 Third Quarter 29-13/16 25-1/4 Fourth Quarter 31-9/16 27-3/16
First Quarter $23-3/8 $20-3/4 Second Quarter 22-1/4 19-7/8 Third Quarter 23 20-13/16 Fourth Quarter 26-1/4 22
-------------------- --------------- --- --------------
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 28, 1999, the closing price of SOUTHERN's common stock was $25.0625.
(b) Number of SOUTHERN's common stockholders at December 31, 1998:
187,053
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 paid and/or declared by SOUTHERN and the operating affiliates to their stockholder(s) for the past two years were as follows: (in thousands)
------------------- --------- ------------- ---------- Registrant Quarter 1998 1997 ------------------- --------- ------------- ----------
SOUTHERN First $232,449 $220,194 Second 233,623 221,544 Third 233,763 222,980 Fourth 233,506 224,287
ALABAMA First 90,400 80,100 Second 90,500 85,600 Third 90,800 86,100 Fourth 95,400 87,800
GEORGIA First 132,100 122,700 Second 132,300 131,000 Third 132,700 131,800 Fourth 139,500 134,500
GULF First 14,100 12,900 Second 14,100 13,800 Third 14,100 13,800 Fourth 14,900 24,100
MISSISSIPPI First 12,700 11,300 Second 12,800 12,100 Third 12,800 12,200 Fourth 13,400 13,800
SAVANNAH First 5,800 5,100 Second 5,800 5,400 Third 5,800 5,500 Fourth 6,100 4,500 ------------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 32.5(cent) for each quarter of 1997 and 33.5(cent) for each quarter of 1998. The dividend paid on SOUTHERN's common stock for the first quarter of 1999 was 33.5(cent) per share.
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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 and the amounts restricted against the payment of cash dividends on common stock at December 31, 1998, were as follows:
-------------------- ------------------ --- -------------- Retained Restricted Earnings Amount ------------------ -------------- (in millions) ALABAMA $1,225 $ 796 GEORGIA 1,780 897 GULF 171 127 MISSISSIPPI 174 118 SAVANNAH 113 68 Consolidated 3,878 2,003 -------------------- ------------------ --- --------------
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-45 through II-48.
ALABAMA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-80 through II-83.
GEORGIA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-118 through II-121.
GULF. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-151 through II-154.
MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-183 through II-186.
SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-211 through II-214.
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-19.
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-52 through II-60.
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-87 through II-96.
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-125 through II-133.
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-158 through II-166.
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-190 through II-197.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in SOUTHERN's "Management's Discussion and Analysis - Derivative Financial Instruments" and to Note 1 to SOUTHERN's financial statements under the headings "Financial Instruments for Non-Trading Activities" and "Financial Instruments for Trading Activities" contained herein on pages II-15 through II-16; and pages II-30 through II-32, respectively.
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III-3
III-4
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT Southern Company and Subsidiary Companies 1998 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 generally accepted accounting principles appropriate in the circumstances 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 books and 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 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 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 generally accepted accounting principles.
/s/ A. W. Dahlberg A. W. Dahlberg Chairman, President, and Chief Executive Officer
/s/ W. L. Westbrook W. L. Westbrook Financial Vice President, Chief Financial Officer, and Treasurer
February 10, 1999
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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, 1998 and 1997, and the related consolidated statements of income, comprehensive income, retained earnings, paid-in capital, accumulated other comprehensive income, and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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-20 through II-44) referred to above present fairly, in all material respects, the financial position of Southern Company and subsidiary companies as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Arthur Andersen LLP
Atlanta, Georgia February 10, 1999
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 1998 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
Southern Company's 1998 earnings of $1.2 billion -- excluding non-recurring items -- established a new record high. Earnings were driven by higher energy sales and from growth in the non-traditional business. However, reported earnings in both 1998 and 1997 reflected significant charges. Reported earnings for 1998 were $977 million or $1.40 per share compared with $972 million or $1.42 per share in 1997. The traditional core business of selling electricity in the southeastern United States remained strong, while the non-traditional business results were adversely affected by a $200 million, after tax, write down of assets in South America in 1998 and by a $111 million windfall profits tax assessed in the United Kingdom in 1997. Southern Company's subsidiary that owns and manages its international and domestic non-traditional electric power production and delivery facilities is Southern Energy, Inc. (Southern Energy). After excluding these non-recurring charges, Southern Energy accounted for approximately 20 percent and 10 percent of Southern Company's reported net income in 1998 and 1997, respectively.
A reconciliation of reported earnings to earnings excluding non-recurring items and explanations are as follows:
Consolidated Earnings Net Income Per Share --------------- ---------------- 1998 1997 1998 1997 ---------------- ---------------- (in millions) Earnings as reported $ 977 $ 972 $1.40 $1.42 - - - - - - - --------------------------------------------------------------- Write down of assets: South American investments 200 - .29 - Rocky Mountain plant 21 - .03 - Windfall profits tax - 111 - .16 Work force reduction programs 20 31 .03 .05 Other 7 16 .01 .02 - - - - - - - --------------------------------------------------------------- Total non-recurring 248 158 .36 .23 - - - - - - - --------------------------------------------------------------- Earnings excluding non-recurring items $1,225 $1,130 $1.76 $1.65 =============================================================== Amount and percent change $95 8.4% $0.11 6.7% - - - - - - - ---------------------------------------------------------------
Southern Energy's 1998 write down is related to its investments in Argentina and Chile not meeting financial expectations, which resulted in an announced plan to sell these assets. In 1997, Southern Energy -- as well as other utilities in the United Kingdom -- was assessed a one-time tax on profits. In 1998, Georgia Power resolved a long-term issue related to its investment in the Rocky Mountain pumped storage hydroelectric plant. The write down resulted from a settlement of Georgia Power's 1998 retail rate proceeding. Also, work force reduction programs in the traditional core business were implemented in 1998 and 1997. These costs are expected to be recovered through future savings within approximately two years following each program's implementation.
Dividends paid on common stock during 1998 were $1.34 per share or 33 1/2 cents per quarter. During 1997 and 1996, dividends paid per share were $1.30 and $1.26, respectively. In January 1999, Southern Company maintained the quarterly dividend at 33 1/2 cents per quarter or $1.34 annually. Southern Company has modified its dividend policy from a targeted 75 percent payout ratio to a lower ratio over time. This policy supports Southern Company's strategic goal to become the best investment in the electric utility industry.
Revenues
Operating revenues changed in 1998 and 1997 as a result of the following factors:
Increase (Decrease) From Prior Year - - - - - - - --------------------------------------------------------------- 1998 1997 1996 - - - - - - - --------------------------------------------------------------- (in millions) Retail -- Growth and price change $ 258 $ 105 $ 124 Weather 178 (110) (64) Fuel cost recovery and other 189 (13) 2 - - - - - - - --------------------------------------------------------------- Total retail 625 (18) 62 - - - - - - - --------------------------------------------------------------- Sales for resale -- Within service area (2) (33) 10 Outside service area 12 81 14 - - - - - - - --------------------------------------------------------------- Total sales for resale 10 48 24 Southern Energy (1,934) 2,154 1,040 Other operating revenues 91 69 52 - - - - - - - --------------------------------------------------------------- Total operating revenues $(1,208) $2,253 $1,178 =============================================================== Percent change (9.6)% 21.8% 12.8% - - - - - - - ---------------------------------------------------------------
Retail revenues of $8.3 billion increased sharply, up 8.2 percent compared with last year. Continued growth in the traditional service area and the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
positive impact of weather on energy sales were the predominant factors causing the rise in revenues. In 1997, retail revenues decreased by 0.2 percent compared with the year 1996. Under fuel cost recovery provisions, fuel revenues generally equal fuel expenses -- including the fuel component of purchased energy -- and do not affect net income.
Sales for resale revenues within the service area were $374 million in 1998, down 0.7 percent from the prior year. Revenues from sales for resale within the service area were $376 million in 1997, down 8.1 percent from the prior year. This sharp decline resulted primarily from supplying less electricity under contractual agreements with certain wholesale customers in 1997.
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 were as follows:
1998 1997 1996 - - - - - - - ---------------------------------------------------------------- (in millions) Capacity $196 $203 $217 Energy 152 183 176 - - - - - - - ---------------------------------------------------------------- Total $348 $386 $393 ================================================================
Capacity revenues in 1998 slightly declined as a result of adjustments and true-ups related to contractual pricing. In 1997, capacity revenues decreased because the amount of capacity under contract declined during 1996. Additional declines in capacity are not scheduled until after 1999.
In 1998, Southern Energy's revenues declined because its energy trading and marketing operations were deconsolidated on January 1, 1998, when Southern Energy's joint venture with Vastar Resources, Inc. (Vastar) became effective. Because of Vastar's significant participation rights in the joint venture, the equity method of accounting is required. This results in Southern Energy's share of the joint venture's earnings being reported in other income in 1998. In 1997, Southern Energy reported energy trading and marketing revenues of $2.0 billion. Southern Energy's revenues in 1998 of $1.9 billion increased $48 million compared with comparable revenues in 1997 that exclude energy trading and marketing. This increase results primarily from operations of assets obtained in domestic acquisitions. In 1997, Southern Energy's revenues rose to $3.8 billion. This increase was primarily attributable to the development and growth of energy trading and marketing activities. In 1997, energy trading and marketing revenues increased $1.9 billion compared with amounts recorded in 1996. However, these revenues were substantially offset by purchased power expenses incurred in completing these trading and marketing transactions. Energy trading and marketing -- similar to other low-margin sales activities -- is dependent on huge volumes for profitability.
Energy Sales
Changes in traditional core business revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1998 and the percent change by year were as follows:
Amount Percent Change (billions of --------- ------------------------------ kilowatt-hours) 1998 1998 1997 1996 - - - - - - - ------------------------------- ------------------------------- Residential 43.5 10.9% (2.2)% 2.5% Commercial 41.7 7.2 2.5 5.7 Industrial 55.3 2.1 2.6 2.2 Other 1.0 3.1 (1.1) 5.7 ----- Total retail 141.5 6.2 1.1 3.3 Sales for resale -- Within service area 9.8 (0.4) (9.6) 15.4 Outside service area 13.0 (5.6) 27.7 17.9 ----- Total 164.3 4.7 2.2 5.0 =================================================================
The rate of growth in 1998 retail energy sales was the highest one-year increase since 1986. Residential energy sales registered the highest annual increase in over two decades as a result of hotter-than-normal weather and the addition of 57,000 new customers. Commercial sales were also affected by the warm weather. Commercial and industrial sales, both in 1998 and 1997, 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. Energy sales to retail customers are projected to increase at an average annual rate of 2.1 percent during the period 1999 through 2009.
Energy sales for resale outside the service area are predominantly unit power sales under long-term contracts to Florida utilities. Economy sales and amounts sold under short-term contracts are also sold for resale outside the service area. Sales to customers outside the service area declined by 5.6 percent in 1998 and increased by 27.7 percent in 1997 when compared with the respective
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
prior year. The wide variances in sales were influenced by fluctuations in prices for oil and natural gas, the primary fuel sources for utilities with which the company has long-term contracts. When oil and gas prices fall below a certain level, these customers can generate electricity to meet their requirements more economically. However, these fluctuations in energy sales under long-term contracts have minimal effects on earnings because Southern Company is paid for dedicating specific amounts of its generating capacity to these utilities outside the service area.
Expenses
Total operating expenses of $9.4 billion -- before write downs -- for 1998 decreased $1.2 billion compared with the prior year. Traditional core business expenses increased $679 million. Southern Energy's expenses decreased $2.0 billion. The decline for Southern Energy corresponds to the decrease in revenues resulting primarily from the deconsolidation of the energy trading and marketing operations as discussed earlier. Approximately $2.0 billion of these expenses were recorded in 1997 purchased power expenses. The costs to produce and deliver electricity for the traditional core business in 1998 increased by $359 million to meet higher energy demands. Non-production operation and maintenance expenses increased $192 million in 1998. Traditional core business depreciation expenses and taxes other than income taxes increased by $142 million as a result of additional utility plant being placed into service and increased accelerated depreciation of certain assets.
In 1997, operating expenses of $10.7 billion increased $2.2 billion compared with 1996. Traditional core business expenses increased $69 million. Southern Energy's expenses increased $2.1 billion. The large increase for Southern Energy resulted primarily from two factors. First, the acquisition of CEPA was first reflected in 1997 expenses. Second, $2.0 billion of energy trading and marketing expenses were included in purchased power expenses. The costs to produce and deliver electricity for the traditional core business in 1997 increased by $37 million to meet higher energy demands. Also, costs related to work force reduction programs decreased in 1997 by $35 million. Traditional core business depreciation expenses and taxes other than income taxes increased by $136 million as a result of additional utility plant being placed into service and increased accelerated depreciation of certain assets.
Fuel costs constitute the single largest expense for Southern Company's traditional core business. 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 core business service area -- were as follows:
1998 1997 1996 - - - - - - - ----------------------------------------------------------------- Total generation (billions of kilowatt-hours) 164 160 156 Sources of generation (percent) -- Coal 77 77 77 Nuclear 16 17 17 Hydro 4 4 4 Oil and gas 3 2 2 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.48 1.46 1.48 - - - - - - - -----------------------------------------------------------------
Total fuel and purchased power costs of $3.6 billion in 1998 decreased $1.7 billion compared with 1997. The traditional core business increased $299 million and Southern Energy decreased $2.0 billion. Southern Energy's reduction in fuel and purchased power costs resulted from $2.0 billion associated with energy trading and marketing expenses recorded in 1997 and from no energy trading costs recorded in purchased power in 1998 as a result of the joint venture with Vastar discussed earlier. The traditional core business's total energy sales rose by 7.4 billion kilowatt-hours more than in 1997. Fuel and purchased power expenses of $5.3 billion in 1997 increased $2.0 billion compared with the prior year. These expenses for traditional core business increased $32 million, and Southern Energy's portion increased $1.9 billion. Southern Energy's increase in expenses escalated as a result of energy trading and marketing activities discussed earlier. The traditional core business's total energy sales went up by 3.4 billion kilowatt-hours more than in 1996. The additional cost to meet the demand was offset slightly by a lower average cost of fuel per net kilowatt-hour generated.
Total interest charges and other financing costs increased $91 million from amounts reported in the previous year. These costs for the traditional core business increased $48 million compared with the reported amounts in 1997. Southern Energy's costs increased $47 million related primarily to financing of acquisitions. In 1997, these same costs for traditional core business were flat, but Southern Energy's interest charges increased $205 million as a result of acquisitions.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
Effects of Inflation
Southern Company's traditional core business 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 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 potential. The level of Southern Company's future earnings depends on numerous factors. Two major factors are: achieving energy sales growth in a less regulated, more competitive environment; and operating non-traditional business activities successfully.
Southern Company continues to position its business to meet the challenges of a new competitive environment. Work force reduction programs have reduced earnings by $20 million, $31 million, and $53 million for the years 1998, 1997, and 1996, respectively. These actions -- in conjunction with other cost containment programs -- will assist efforts to continue being a low-cost provider of electricity.
The operating companies currently operate as vertically integrated companies providing electricity to customers within the traditional service area of the southeastern United States. Prices for electricity provided by the operating companies to retail customers are set by state public service commissions under cost-based regulatory principles.
Rates for Alabama Power and Mississippi Power are adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return. In December 1998, Georgia Power received a new three-year retail rate order. As a result of the rate order, Georgia Power recorded in 1998 a write down of $34 million -- $21 million after taxes -- related to its investment in the Rocky Mountain pumped storage hydroelectric plant. This long-standing issue is now resolved. See Note 3 to the financial statements for additional information about these matters and other retail and wholesale regulatory matters.
Future earnings for the operating companies 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 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 being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Southern Company is aggressively working to maintain and expand its share of wholesale sales in the Southeastern power markets.
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 various restructuring and competition initiatives have been or are being discussed in Alabama, Florida, Georgia, and Mississippi, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. The inability of an operating 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 of that operating company. The operating companies are attempting to minimize or reduce their cost exposure. See Note 3 to the financial statements for information regarding these efforts.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, unless Southern Company remains a low-cost producer and provides quality service, the company's retail 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.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators and foreign utility companies to sell power largely free of regulation under PUHCA. These entities are able to sell power to affiliates -- under certain restrictions -- and to own and operate power generating facilities in other domestic and international markets. To take advantage of existing and evolving opportunities, Southern Energy -- founded in 1981 -- is focused on several key international and domestic business lines, including energy distribution, integrated utilities, stand-alone generation, and other energy-related products and services. As the energy marketplace evolves, Southern Energy continues to position the company to become a major competitor. At December 31, 1998, Southern Energy's total assets amounted to $12 billion.
During 1998, Southern Energy further refined its business strategy to focus on a few geographic regions of the world. In Asia, Southern Energy will focus primarily on China, the Philippines, and India. In South America, the company will pursue opportunities in Brazil. In Europe, Southern Energy will concentrate efforts on the European Union countries. And in North America, the company will target efforts in the Northeast, the Midwest, Texas, and California. Southern Energy announced in 1998 plans to acquire, build, or gain access to some 20,000 megawatts of generating capacity in North America over the next several years in order to be competitive in the country's evolving competitive energy supply business. These assets will be closely linked with Southern Energy's energy trading and marketing business. In January 1998, Southern Energy entered into a joint venture with Vastar. The two companies combined their energy trading and marketing operations to form a new full-service energy provider, Southern Company Energy Marketing. The joint venture agreement gives Southern Company Energy Marketing rights to market virtually all of Vastar's natural gas production over the next 10 years.
In December 1998, Southern Energy completed its $537 million purchase of 1,267 megawatts of generating capacity from Commonwealth Electric. In addition, Southern Energy plans to add 685 megawatts of capacity at the plants. In late 1998, Southern Energy announced the $801 million planned acquisition of 3,065 megawatts of generating capacity from Pacific Gas & Electric in northern California. Additionally, the company announced plans to acquire from Orange and Rockland Utilities Inc. and Consolidated Edison Inc. in New York 1,776 megawatts of capacity for $480 million. These transactions are expected to close during 1999. Additionally, Southern Energy has announced plans to build or purchase an additional 680 megawatts of capacity in Texas and Wisconsin. Through Southern Company Energy Marketing, the company has also gained access to additional capacity through marketing agreements. The company has access to almost 2,000 megawatts of capacity through marketing agreements with Sithe Energies in New York and Brazos Electric Cooperative in Texas.
After refining its international focus and reviewing the financial performance of existing assets, Southern Energy announced plans to sell its holdings in EDELNOR in Chile and Alicura in Argentina. As a result, Southern Energy recorded a write down of $200 million, after tax, in December 1998 related to these holdings. Because of regulatory and market conditions, these assets did not meet earnings expectations.
Southern Company has filed with the Securities and Exchange Commission (SEC) a request to invest up to nearly $8 billion in the non-traditional domestic and international business. The current SEC authority is $3.9 billion, of which $3.6 billion has been invested as of December 31, 1998.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
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) has decided to review 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 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 operating companies are subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of a company's operations is no longer subject to these provisions, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by the year 2000. This statement establishes accounting and reporting standards for derivative instruments -- including certain derivative instruments embedded in other contracts -- and for hedging activities. Southern Company has not yet quantified the impact of adopting this statement on its financial statements; however, the adoption could increase volatility in earnings and other comprehensive income.
In March 1998, the American Institute of Certified Public Accountants (AICPA) issued a new Statement of Position, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement requires capitalization of certain costs of internal-use software. Southern Company adopted this statement in January 1999, and it is not expected to have a material impact on the consolidated financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the Cost of Start-up Activities. This statement requires that the costs of start-up activities and organizational costs be expensed as incurred. Any of these costs previously capitalized by a company must be written off in the year of adoption. Southern Company adopted this statement in January 1999, and it is not expected to have a material impact on the consolidated financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The EITF requires that energy trading contracts must be marked to market through the income statement, with gains and losses reflected rather than revenues and purchased power. Energy trading contracts are defined as energy contracts entered into with the objective of generating profits on or from exposure to shifts or changes in market prices. Southern Company adopted the required accounting in January 1999, and it is not expected to have a material impact on the consolidated financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s shortened the year portion of date entries to just two digits. Computers assumed, in effect, that all years began with "19." This practice was widely adopted and hard-coded into computer chips and processors found in some equipment. This approach, intended to save processing time and storage space, was used until the mid-1990s. Unless corrected before the Year 2000, affected software systems and devices containing a chip or microprocessor with date and time functions could incorrectly process dates or the systems may cease to function.
Southern Company depends on complex computer systems for many aspects of its operations, which include generation, transmission, and distribution of electricity, as well as other business support activities. Southern Company's goal is to have critical devices or software that are required to maintain operations to be Year 2000 ready by June 1999. Year 2000 ready means that a system or application is determined suitable for continued use through the Year
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
2000 and beyond. Critical systems include, but are not limited to, reactor control systems, safe shutdown systems, turbine generator systems, control center computer systems, customer service systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
Southern Company's executive management recognizes the seriousness of the Year 2000 challenge and has dedicated what it believes to be adequate resources to address the issue. The Millennium Project is a team of employees, IBM consultants, and other contractors whose progress is reviewed on a monthly basis by a steering committee of Southern Company executives.
Southern Company's traditional business refers to the integrated utility services within Alabama, Florida, Georgia, and Mississippi. For this traditional business, the work was divided into two phases. Phase I began in 1996 and consisted of identifying and assessing corporate assets related to software systems and devices that contain a computer chip or clock. The first phase was completed in June 1997. Phase 2 consists of testing and remediating high priority systems and devices. Also, contingency planning is included in this phase. Completion of Phase 2 is targeted for June 1999. The Millennium Project will continue to monitor the affected computer systems, devices, and applications into the Year 2000.
For the traditional business, Southern Company has completed more than 70 percent of the activities contained in its work plan. The percentage of completion and projected completion by function are as follows:
Work Plan - - - - - - - ---------------------------------------------------------------------- Remediation Project Inventory Assessment Testing Completion - - - - - - - ---------------------------------------------------------------------- Generation 100% 100% 70% 6/99 Energy Management 100 100 90 6/99 Transmission and Distribution 100 100 100 1/99 Telecommunications 100 100 50 6/99 Corporate Applications 100 100 90 3/99 - - - - - - - ----------------------------------------------------------------------
For the non-traditional business located in the United States and several countries throughout the world, Year 2000 readiness is generally scheduled to follow the traditional business. In a number of the business units outside the United States, Southern Company is neither the majority owner nor the managing concern. In these circumstances, Southern Company is providing technical assistance but does not control the schedule or progress.
Year 2000 Costs
For the traditional business, current projected total costs for Year 2000 readiness are approximately $91 million, which includes $6 million of cost billed to non-affiliated companies. These costs include labor necessary to identify, test, and renovate affected devices and systems. From its inception through December 31, 1998, the Year 2000 program costs, recognized primarily as expense, amounted to $56 million based on Southern Company's ownership interest. In addition to the traditional business costs, current projections for Year 2000 program costs are approximately $24 million for the non-traditional business -- based on Southern Company's ownership interest -- of which $9 million has been spent through December 31, 1998
Year 2000 Risks
Southern Company is implementing a detailed process to minimize the possibility of service interruptions related to the Year 2000. The company believes, based on current tests, that the system can provide customers with electricity. These tests increase confidence, but do not guarantee error-free operations. The company is taking what it believes to be prudent steps to prepare for the Year 2000, and it expects any interruptions in service that may occur within the traditional business service territory to be isolated and short in duration.
Southern Company expects the risks associated with Year 2000 to be no more severe than the scenarios that its electric system is routinely prepared to handle. The most likely worst case scenario consists of the service loss of one of the largest generating units and/or the service loss of any single bulk transmission element in its traditional business service territory. The company has followed a proven methodology for identifying and assessing software and devices containing potential Year 2000 challenges. Remediation and testing of those devices are in progress. Following risk assessment, Southern Company is preparing contingency plans as appropriate and is participating in North American Electric Reliability Council-coordinated national drills during 1999.
Southern Company is currently reviewing the Year 2000 readiness of material third parties that provide goods and services crucial to Southern Company's operations. Among such critical third parties are fuel, transportation, telecommunications, water, chemical, and other suppliers. Contingency plans based on the assessment of each third party's ability to continue supplying critical goods and services to Southern Company are being developed.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
There is a potential for some earnings erosion caused by reduced electrical demand by customers because of their own Year 2000 issues. The risk associated with the progress of some operations outside the United States is a function of the local regulatory environment and the priorities of the entities with management control. Year 2000 issues are included in the list of due diligence activities associated with acquisitions; there is some risk associated with the subsequent validation of any given seller's representations.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the traditional business is skilled at developing and using contingency plans in unusual circumstances. As part of Year 2000 business continuity and contingency planning, Southern Company is drawing on that experience to make risk assessments and is developing additional plans to deal specifically with situations that could arise relative to Year 2000 challenges. Southern Company is identifying critical operational locations, and key employees will be on duty at those locations during the Year 2000 transition. In September 1999, drills are scheduled to be conducted to test contingency plans. Because of the level of detail of the contingency planning process, management feels that the contingency plans will keep any service interruptions that may occur within the traditional business service territory isolated and short in duration.
Contingency planning efforts for the non-traditional business are generally in the initial phase.
FINANCIAL CONDITION
Overview
Southern Company's financial condition continues to remain strong. The company's common stock closed 1998 with the highest year-end closing price in history. Consolidated net income of $1.2 billion -- excluding non-recurring charges -- in 1998 increased $95 million compared with the prior year. In January 1999, Southern Company modified its dividend policy to lower, over time, the previously targeted payout ratio of approximately 75 percent. The quarterly dividend declared was maintained at 33 1/2 cents per share or $1.34 annually. This action allows more internally generated funds to be reinvested in the company, which is expected to increase long-term shareholder value.
Gross property additions to utility plant were $2.0 billion in 1998. The majority of funds needed for gross property additions since 1995 has been provided from operating activities. Southern Energy acquired $670 million of generating assets in 1998 and sold an additional 26 percent interest in its United Kingdom subsidiary for $170 million. The Consolidated Statements of Cash Flows provide additional details.
Derivative Financial Instruments
Southern Company is exposed to market risks, including changes in interest rates, currency exchange rates, and certain commodity prices. To manage the volatility attributable to these exposures, the company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the company's policies in areas such as counterparty exposure and hedging practices. Generally, company policy is that derivatives are to be used only for hedging purposes. Derivative positions are monitored using techniques that include market value and sensitivity analysis.
The company's market risk exposures relative to interest rate changes and currency exchange fluctuations, as discussed later, 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.
Interest rate swaps are used to hedge underlying debt obligations. These swaps hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. Additionally, the company has interest rate swaps in foreign currencies. These swaps are designated as hedges of the company's related debt issuance in the same currency.
If the company sustained a 100 basis point change in interest rates for all variable rate debt in all currencies, the change would affect annualized interest expense by approximately $35 million at December 31, 1998. Based on the company's overall interest rate exposure at December 31, 1998, 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.
The company has investments in the United Kingdom and Germany. For these investments, the company uses long-term cross-currency agreements to reduce a substantial portion of its exposure to fluctuations in the British pound sterling and German Deutschemark. These instruments are used to hedge the net investments in these countries. As a result of these swaps, a 10 percent
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
sustained decline of the British pound sterling and German Deutschemark versus the U.S. dollar would not materially affect the consolidated financial statements.
The company also has investments in various emerging market countries where the net investments are not hedged, including Argentina, Brazil, Chile, Trinidad, Bahamas, Philippines, and China. The company relies on either currency pegs or contractual or regulatory links to the U.S. dollar to mitigate currency risk attributable to these investments. The company does not believe it has a material exposure to changes in exchange rates between the U.S. dollar and the currencies of these countries.
Based on availability and economics, the company also uses currency swaps and forward agreements to hedge dollar-denominated debt issued by subsidiaries with a functional currency other than the U.S. dollar. These swaps offset the dollar cash flows, thereby effectively converting debt to the respective company's reporting currency. Gains and losses related to qualified hedges of foreign currency firm commitments are deferred and included in the basis of the underlying transactions. To the extent that a qualifying hedge is terminated or ceases to be effective as a hedge, any deferred gains and losses to that point continue to be deferred and are included in the basis of the underlying transaction.
In addition to the non-trading activities, the company is exposed to market risks through its electricity and natural gas commodity trading business, which is primarily conducted through the company's joint venture relationship with Vastar. While this joint venture relationship is accounted for under the equity method of accounting, Southern Company -- through guarantees it has made jointly with Vastar -- is exposed to market risk. Southern Company and Vastar have agreed to indemnify each other against losses under such guarantees in proportion to their respective ownership shares of the joint venture. At December 31, 1998, outstanding guarantees related to the estimated fair value of net contractual commitments were approximately $152 million. Based upon the joint venture's statistical analysis of its credit risk, Southern Company's potential exposure under these contractual commitments would not materially differ from the estimated fair value. The joint venture's gross revenues and cost of sales for 1998 were $9.2 billion and $9.1 billion, respectively.
To estimate and manage the market risk of its trading and marketing portfolio, the joint venture employs a daily Value at Risk (VAR) methodology. VAR is used to describe a probabilistic approach to measuring the exposure to market risk. VAR models are relatively sophisticated. However, the quantitative risk information is limited by the parameters established in creating the model. The instruments being evaluated may have features that may trigger a potential loss in excess of calculated amounts if the changes in commodity prices exceed the confidence level of the model used. The calculation utilizes the standard deviation of seasonally adjusted historical changes in the value of the market risk sensitive commodity-based financial instruments to estimate the amount of change (i.e., volatility) in the current value of these instruments that could occur at a specified confidence level over a specified holding interval. The parameters used in the calculation include holding intervals ranging from five to 20 days, depending upon the type of instrument, the term of the instrument, the liquidity of the underlying market, and other factors. The models employ a 95 percent confidence level based on historical price movement. Based on the joint venture's VAR analysis of its overall commodity price risk exposure at December 31, 1998, management does not anticipate a materially adverse effect on the company's consolidated financial statements as a result of market fluctuations.
In the United Kingdom, the company utilizes contracts to mitigate its exposure to volatility in the prices of electricity purchased through the wholesale electricity market. These contracts allow the company to effectively convert the majority of its anticipated wholesale electricity purchases from market prices to fixed prices. The gains and losses on these contracts are deferred and recognized as electricity is purchased. Recently, a market has developed for trading these contracts in the United Kingdom. However, due to the immaturity of this market and the complexity of the company's existing contracts, it is not practicable to estimate the fair value of these contracts.
Due to cost-based rate regulations, the operating companies have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the operating 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, 1998, 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 and Trading Activities."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
Capital Structure
Southern Company achieved a ratio of common equity to total capitalization -- including short-term debt -- of 37.4 percent in 1998, compared with 38.6 percent in 1997, and 45.1 percent in 1996.
During 1998, the subsidiary companies sold, through public authorities, $210 million of pollution control revenue bonds. In addition, preferred stock of $200 million and capital and preferred securities of $435 million were issued in 1998. The companies continued to reduce financing costs by retiring higher-cost bonds and preferred stock. Retirements, including maturities, of bonds totaled $1.7 billion during 1998, $507 million during 1997, and $600 million during 1996. As a result, the composite interest rate on long-term debt decreased from 7.1 percent at December 31, 1995 to 6.42 percent at December 31, 1998. Retirements of preferred stock totaled $239 million during 1998, $660 million during 1997, and $179 million during 1996.
In 1998, Southern Company raised net proceeds of $109 million from the issuance of common stock under the company's various stock plans. At the close of 1998, the company's common stock had a market value of 29 1/16 per share, compared with a book value of $14.04 per share. The market-to-book value ratio was 207 percent at the end of 1998, compared with 186 percent at year-end 1997, and 166 percent at year-end 1996.
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $2.6 billion for 1999, $2.1 billion for 2000, and $2.1 billion for 2001. 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.
The operating companies have approximately 2,700 megawatts of combined cycle generation scheduled to be placed in service by 2001. Southern Energy has under construction some 1,300 megawatts of owned capacity. Significant construction of transmission and distribution facilities and upgrading of generating plants will be continuing for the core business in the Southeast.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.6 billion will be required by the end of 2001 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.
In late 1998, Southern Energy announced plans to acquire $801 million and $480 million of generating assets in California and New York, respectively. These transactions are expected to close in 1999.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Southern 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 initially affected 28 generating units of Southern Company. As a result of the company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
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 $300 million.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Current compliance strategy for Phase II and ozone non-attainment could require total estimated construction expenditures of approximately $70 million, of which $16 million remains to be spent.
A significant portion of costs related to the acid rain provision 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 1998 Annual Report
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. In September 1998, the EPA issued the final regional nitrogen oxide rules to the states for implementation. The states have one year to adopt and implement the new rules. The final rules affect 22 states including Alabama and Georgia. The EPA rules are being challenged in the courts by several states and industry groups. Implementation of the final state rules could require substantial further reductions in nitrogen oxide emissions from fossil-fired generating facilities and other industry in these states. Implementation of the standards could result in significant additional compliance costs and capital expenditures that cannot be determined until the results of legal challenges are known and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: nitrogen oxide emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; control strategies to reduce regional haze; and hazardous waste disposal requirements. The impact of 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 $6 million in 1998 and $4 million in 1997. In 1996, the company was reimbursed $6 million for amounts previously expensed. 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 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 1999 -- 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. Any portion of the common stock required during 1999 for the company's stock plans that is not provided from the issuance of new stock will be acquired on the open market in accordance with the terms of such plans.
The operating companies plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from internal sources. However, the type and timing of any financings - - - - - - - -- if needed -- will depend on market conditions and regulatory approval.
The operating companies historically have relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control revenue bonds issued for their benefit by public authorities, to meet their long-term external financing requirements. Recently, the operating companies' financings have consisted of unsecured debt and trust preferred securities. In this regard, the operating companies sought and obtained stockholder approval in 1997 or 1998 to amend their respective corporate charters eliminating restrictions on the amounts of unsecured indebtedness they may incur.
To meet short-term cash needs and contingencies, Southern Company had approximately $872 million of cash and cash equivalents and $4.6 billion of unused credit arrangements with banks at the beginning of 1999.
Cautionary Statement Regarding Forward-Looking Information
Southern Company's 1998 Annual Report contains forward-looking and historical information. The company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking information; accordingly, there can be no assurance that such
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1998 Annual Report
indicated results will be realized. These factors include legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry; the extent and timing of the entry of additional competition in the markets of the subsidiary companies; potential business strategies - - - - - - - --including acquisitions or dispositions of assets or internal restructuring -- that may be pursued by the company; state and federal rate regulation in the United States; Year 2000 issues; changes in or application of environmental and other laws and regulations to which the company and its subsidiaries are subject; political, legal and economic conditions and developments in the United States and in foreign countries in which the subsidiaries operate; financial market conditions and the results of financing efforts; changes in commodity prices and interest rates; 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; and other factors discussed in the reports -- including Form 10-K -- filed from time to time by the company with the SEC.
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CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1998, 1997, and 1996 Southern Company and Subsidiary Companies 1998 Annual Report
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CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1998, 1997, and 1996 Southern Company and Subsidiary Companies 1998 Annual Report
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CONSOLIDATED BALANCE SHEETS At December 31, 1998 and 1997 Southern Company and Subsidiary Companies 1998 Annual Report
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CONSOLIDATED BALANCE SHEETS (continued) At December 31, 1998 and 1997 Southern Company and Subsidiary Companies 1998 Annual Report
11-23
CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 1998 and 1997 Southern Company and Subsidiary Companies 1998 Annual Report
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CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 1998 and 1997 Southern Company and Subsidiary Companies 1998 Annual Report
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 1998, 1997, and 1996 Southern Company and Subsidiary Companies 1998 Annual Report
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NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of five operating companies, a system service company, Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), and other direct and indirect subsidiaries. The operating companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four southeastern states. Contracts among the operating companies -- dealing with 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. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The operating companies also are subject to regulation by the FERC and their respective state public service commissions. The companies follow generally accepted accounting principles and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates, and the actual results may differ from those estimates. All material intercompany items have been eliminated in consolidation.
The consolidated financial statements reflect investments in controlled subsidiaries on a consolidated basis and other investments on an equity basis. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform with the current year presentation.
Regulatory Assets and Liabilities
The operating companies are subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the operating companies 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:
1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Deferred income taxes $1,036 $1,142 Deferred Plant Vogtle costs - 50 Premium on reacquired debt 294 285 Demand-side programs - 11 Department of Energy assessments 57 63 Vacation pay 81 79 Deferred fuel charges - 4 Postretirement benefits 36 38 Work force reduction costs 17 37 Deferred income tax credits (715) (746) Storm damage reserves (24) (36) Other, net 145 152 - - - - - - - --------------------------------------------------------------- Total $ 927 $1,079 ===============================================================
In the event that a portion of an operating company's operations is no longer subject to the provisions of FASB Statement No. 71, the company would be required to write off related net 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 operating companies accrue revenues for service rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The operating companies' electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates.
Southern Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $133 million in 1998, $144 million in 1997, and $142 million in 1996. 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. Although disposal was scheduled to begin in 1998, the actual year this service will begin is uncertain. The DOE failed to begin disposing of spent fuel in January 1998, as required by the contracts, and the companies are pursuing legal remedies against the government for breach of contract. Sufficient storage capacity currently is available to permit operation into 2003 at Plant Hatch, into 2017 at Plant Vogtle, and into 2009 and 2013 at Plant Farley units 1 and 2, respectively. Plant Vogtle's spent fuel storage capacity includes the installation in 1998 of additional rack capacity. Activities for adding dry cask storage capacity at Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 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, 1998, under this law to be approximately $31 million and $24 million. These obligations are recorded in the Consolidated 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 3.4 percent in 1998, 3.4 percent in 1997, and 3.3 percent in 1996. 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 costs of decommissioning nuclear facilities and removal of other facilities.
Georgia Power recorded additional depreciation of electric plant amounting to $316 million in 1998, $159 million in 1997, and $24 million in 1996. The accumulated depreciation related to these charges is $505 million at December 31, 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 1998 Annual Report
of December 31, 1998, 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 1997 1997 Decommissioning periods: Beginning year 2017 2014 2027 Completion year 2031 2027 2038 - - - - - - - --------------------------------------------------------------- (in millions) Site study costs: Radiated structures $629 $372 $317 Non-radiated structures 60 33 44 - - - - - - - --------------------------------------------------------------- Total $689 $405 $361 =============================================================== (in millions) Ultimate costs: Radiated structures $1,868 $722 $ 922 Non-radiated structures 178 65 129 - - - - - - - ---------------------------------------------------------------- Total $2,046 $787 $1,051 ================================================================
Significant assumptions: Inflation rate 4.5% 3.6% 3.6% Trust earning rate 7.0 6.5 6.5 - - - - - - - ----------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the respective state public service commissions. The amount expensed in 1998 and fund balances were as follows:
Plant Plant Plant Farley Hatch Vogtle - - - - - - - --------------------------------------------------------------- (in millions) Amount expensed in 1998 $ 18 $ 11 $ 9 Accumulated provisions: Balance in external trust funds $232 $172 $112 Balance in internal reserves 42 19 12 - - - - - - - --------------------------------------------------------------- Total $274 $191 $124 ===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site study. For Georgia Power effective January 1, 1999, the GPSC increased the annual provision for decommissioning expenses to $26 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. Significant assumptions include an estimated inflation rate of 3.6 percent and an estimated trust earnings rate of 6.5 percent. 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.
Utility Plant
Utility plant is stated at original cost less regulatory disallowances. 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.
Property Rights
Included in property rights are leasehold interests in Southern Energy's power generation facilities that are developed under build, operate, and transfer agreements with foreign governments. Southern Energy's construction costs are initially recorded as construction work in progress, and -- after completion -- these costs are recorded as leasehold interests. These costs are amortized over the length of time the facility is operated before transferring ownership to the local government. Also included in property rights is a concession agreement assigned in 1993 by the Argentine government to Southern Energy for the operation of a hydroelectric plant.
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.
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
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.
Foreign Currency Translation
Assets and liabilities of Southern Company's international operations, where the local currency is the functional currency, have been translated at year-end exchange rates, and revenues and expenses have been translated using average exchange rates prevailing during the year. Adjustments resulting from translation have been recorded in other comprehensive income. The financial statements of international operations, where the U.S. dollar is the functional currency, reflect certain transactions denominated in the local currency that have been remeasured in U.S. dollars. The remeasurement of local currencies into U.S. dollars creates gains and losses from foreign currency transactions that are included in consolidated net income. Foreign exchange gains and losses are not material for all periods presented.
Comprehensive Income
In 1998, Southern Company adopted FASB Statement No. 130, Reporting Comprehensive Income. This statement establishes rules for the reporting and display of comprehensive income and its components. Comprehensive income consists of net income and foreign currency translation adjustments and 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
Non-trading derivative financial instruments are used 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 when the hedged transaction occurs.
The company utilizes interest rate swaps and cross currency interest rate swaps to minimize borrowing costs by changing the interest rate and currency of the original borrowing. For qualifying hedges, the interest rate differential is reflected as an adjustment to interest expense over the life of the swaps.
Southern Company's international operations are exposed to the effects of foreign currency exchange rate fluctuations. To protect against this exposure, the company utilizes currency swaps to hedge its net investment in certain foreign subsidiaries, which has the effect of converting foreign currency cash inflows into U.S. dollars at fixed exchange rates. Gains or losses on these currency swaps, designated as hedges of net investments, are offset against the translation effects reflected in other comprehensive income, net of tax.
Non-trading financial derivative instruments held at December 31, 1998, were as follows:
Year of Unrecognized Maturity or Notional Gain Type Termination Amount (Loss) - - - - - - - ------------------------------- ---------------------------- (in millions) Interest rate swaps: 2002-2016 $928 $(69) 2001-2012 (pound)600 $(130) 2002-2007 DM691 $(30) Cross currency swaps 2001-2007 (pound)429 $11 Cross currency swaption 2003 DM555 $(18) - - - - - - - ---------------------------------------------------------------- (pound) - Denotes British pound sterling. DM - Denotes Deutschemark.
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.
In the United Kingdom, the company utilizes contracts to mitigate its exposure to volatility in the prices of electricity purchased through the wholesale electricity market. These contracts allow the company to effectively convert the majority of its anticipated wholesale electricity purchases from market prices to fixed prices. The gains and losses on these contracts are deferred and recognized as electricity is purchased. Recently, a market has developed for trading these contracts in the United Kingdom. However, due to the immaturity of this market and the complexity of the company's existing contracts, it is not practicable to estimate the fair value of these contracts.
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
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, 1998 $11,777 $11,626 At December 31, 1997 10,916 11,160 Capital and preferred securities: At December 31, 1998 2,179 2,288 At December 31, 1997 1,744 1,826 - - - - - - - ----------------------------------------------------------------
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.
Financial Instruments for Trading Activities
Effective in January 1998, Southern Energy and Vastar Resources, Inc. (Vastar) combined their energy trading and marketing activities to form a joint venture. Southern Energy's investment in the joint venture is accounted for under the equity method of accounting. See Note 5 under "Energy Trading and Marketing Commitments" for additional information. Financial statement disclosure related to Southern Energy's energy trading and marketing activities for 1997 -- prior to the formation of the joint venture was presented as follows:
Derivative financial instruments used for trading purposes primarily relate to commodities associated with the energy sector, such as electricity, natural gas, and crude oil. These instruments were recorded at fair value for balance sheet purposes. The determination of fair value considers various factors, such as closing exchange prices, broker price quotations, and model pricing. Model pricing considers time value and volatility factors underlying any options and contractual commitments. These transactions were accounted for using the mark-to-market method of accounting in which the unrealized gains or losses resulting from the impact of price movements are recognized as net gains or losses in the consolidated statements of income. If the company has a master netting agreement with counterparties, net positions were recognized for consolidated balance sheet and income statement purposes.
In 1997, the company provided price risk management services by entering into a variety of contractual commitments such as price cap and floor agreements, futures contracts, forward purchase and sale agreements, and option contracts. These contracts generally require future settlement, and are either executed on an exchange or traded as over-the-counter (OTC) instruments. Contractual commitments had widely varying terms and durations that ranged from a few hours to a number of years depending on the instrument. The majority of the company's transactions at December 31, 1997, were short-term in duration, with a weighted average maturity of approximately 1.3 years.
All contractual commitments used for trading purposes were recorded at fair value. Contracts in a net receivable position, as well as options held, were reported as assets. Similarly, contractual commitments in a net payable position, as well as options written, were reported as liabilities. The net unrealized gain from risk management services amounted to $8 million at December 31, 1997. Contractual commitments reflected in the Consolidated Balance Sheets at December 31, 1997 were as follows:
Net Notional Fair Value Amounts -------------------- 1997 (Kilowatt-Hours) Assets Liabilities - - - - - - - ----- ------------------------------------------- (in millions) Exchange-issued products: Futures contracts 904 $14 $15 Other 958 1 1 - - - - - - - --------------------------------------------------------------- Total 1,862 15 16 - - - - - - - --------------------------------------------------------------- OTC products: Forward contracts 2,643 69 62 Swaps (473) 1 - Other 639 9 8 - - - - - - - --------------------------------------------------------------- Total 2,809 79 70 - - - - - - - --------------------------------------------------------------- Total 4,671 $94 $86 ===============================================================
Notional amounts -- stated in equivalent millions of kilowatt-hours -- are indicative only of the volume of activity and are not a measure of market risk. Notional amounts of natural gas and crude oil positions are reflected in equivalent kilowatt-hours based on standard conversion rates.
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The annual average gross balances of the company's options and contractual commitments used for trading purposes, based on month-end balances were as follows:
Average Fair Value ----------------------------- 1997 Assets Liabilities - - - - - - - ---- ----------------------------- (in millions) Commodity instruments: Electricity $97 $94 Gas 6 6 Other 7 6 - - - - - - - -----------------------------------------------------------------
2. RETIREMENT BENEFITS
Southern Company has defined benefit, trusteed, pension plans that cover substantially all employees. In the United States, 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 operating companies fund trusts to the extent deductible under federal income tax regulations or to the extent required by their respective regulatory commissions. In 1998, Southern Company adopted FASB Statement No. 132 Employers' Disclosure about Pensions and Other Postretirement Benefits. The measurement date is September 30 for each year.
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 --------------------- 1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Balance at beginning of year $3,701 $3,624 Service cost 99 94 Interest cost 273 271 Benefits paid (201) (163) Actuarial (gain) loss 298 (125) - - - - - - - ---------------------------------------------------------------- Balance at end of year $4,170 $3,701 ================================================================
Plan Assets -------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Balance at beginning of year $5,931 $5,212 Actual return on plan assets 223 911 Employer contributions 4 9 Benefits paid (180) (201) - - - - - - - --------------------------------------------------------------- Balance at end of year $5,978 $5,931 ===============================================================
The accrued pension costs recognized in the Consolidated Balance Sheet were as follows:
1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Funded status $ 1,808 $ 2,230 Unrecognized transition obligation (89) (101) Unrecognized prior service cost 119 126 Unrecognized net gain (1,347) (1,874) Fourth quarter contributions - 2 - - - - - - - ---------------------------------------------------------------- Prepaid asset recognized in the Consolidated Balance Sheets $ 491 $ 383 ================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - ---------------------------------------------------------------- (in millions) Service cost $ 99 $ 94 $ 99 Interest cost 273 271 267 Expected return on plan assets (425) (394) (378) Recognized net gain (47) (42) (29) Net amortization (9) (9) (12) - - - - - - - ---------------------------------------------------------------- Net pension cost (income) $(109) $ (80) $ (53) ================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits were:
1998 1997 - - - - - - - ----------------------------------------------------------------- Discount 6.75% 7.50% Annual salary increase 4.25 5.00 Long-term return on plan assets 8.50 8.50 - - - - - - - -----------------------------------------------------------------
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations ------------------ 1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Balance at beginning of year $ 935 $870 Service cost 18 18 Interest cost 69 67 Benefits paid (35) (27) Actuarial (gain) loss 50 7 - - - - - - - ---------------------------------------------------------------- Balance at end of year $1,037 $935 ================================================================
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Plan Assets --------------------- 1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Balance at beginning of year $294 $260 Actual return on plan assets 8 32 Employer contributions 69 29 Benefits paid (35) (27) - - - - - - - ---------------------------------------------------------------- Balance at end of year $336 $294 =================================================================
The accrued postretirement costs recognized in the Consolidated Balance Sheet were as follows:
1998 1997 - - - - - - - ----------------------------------------------------------------- (in millions) Funded status $(701) $(641) Unrecognized transition obligation 219 233 Unrecognized prior service cost - (4) Unrecognized net loss (gain) 117 68 Fourth quarter contributions 30 41 - - - - - - - ----------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $(335) $(303) =================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - ----------------------------------------------------------------- (in millions) Service cost $ 18 $ 18 $ 20 Interest cost 69 66 60 Expected return on plan assets (21) (18) (14) Recognized net gain 2 3 3 Net amortization 14 17 15 - - - - - - - -------------------------------------------------------------- Net postretirement cost $ 82 $ 86 $ 84 ==============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.30 percent for 1998, decreasing gradually to 4.75 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, 1998 as follows:
1 Percent 1 Percent Increase Decrease - - - - - - - ---------------------------------------------------------------- (in millions) Benefit obligation $75 $(63) Service and interest costs 7 (6) - - - - - - - ----------------------------------------------------------------
Work Force Reduction Programs
Southern Company has incurred additional costs for work force reduction programs. The costs related to these programs were $32 million, $50 million, and $85 million, for the years 1998, 1997, and 1996, respectively. In addition, certain costs of these programs were deferred and are being amortized in accordance with regulatory treatment. The unamortized balance of these costs was $17 million at December 31, 1998.
3. LITIGATION AND REGULATORY MATTERS
Alabama Power Appliance Warranty Litigation
In 1996, a class action against Alabama Power was filed charging Alabama Power with fraud and non-compliance with regulatory statutes relating to the offer, sale, and financing of "extended service contracts" in connection with the sale of electric appliances. The plaintiffs seek damages in an unspecified amount. Alabama Power has offered extended service agreements to its customers since January 1984, and approximately 175,000 extended service agreements could be involved in these proceedings. The trial court has granted partial summary judgment in favor of the plaintiffs. Alabama Power has appealed this decision to the Supreme Court of Alabama. The final outcome of this case cannot now be determined.
Alabama Power Environmental Litigation
On November 30, 1998, total judgments of nearly $53 million were entered in favor of five plaintiffs against Alabama Power and two large textile manufacturers. The plaintiffs alleged that the manufacturers had discharged certain polluting substances into a stream that empties into Lake Martin, a hydroelectric reservoir owned by Alabama Power, and that such discharges had reduced the value of the plaintiffs' residential lots on Lake Martin. Of the total amount of the judgments, $155 thousand was compensatory damages and the remainder was punitive damages. The damages were assessed against all three defendants jointly. Post-trial motions have been filed, and, if relief is not granted at the trial court level, Alabama Power will appeal these judgments to the Supreme Court of Alabama. While Alabama Power believes that these judgments should be reversed or set aside, the final outcome of this matter cannot now be determined.
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
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, 1998, Georgia Power had recorded approximately $5 million in cumulative expenses associated with the site. This represents Georgia Power's agreed-upon share of the removal and remedial investigation and feasibility study costs.
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.
FERC Review of Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of the administrative law judge's opinions in two proceedings in which the return on common equity component of formula rates contained in substantially all of the operating companies' wholesale power contracts was being challenged as unreasonably high. These orders resulted in no change in the wholesale power contracts that were the subject of such proceedings. The FERC also dismissed a complaint filed by three customers under long-term power sales agreements seeking to lower the equity return component in such agreements. These customers have filed applications for rehearing regarding each FERC order. In response to a requirement of the September 1998 FERC orders, Southern Company filed a new equity return component on the long-term power sales contracts, to be effective January 5, 1999. The proposed equity return was lowered from 13.75 percent to 12.50 percent. If the filed equity return is approved, the estimated impact on Southern Company's revenues will be approximately $7 million annually. The FERC placed the new rates into effect subject to refund. Also, this filing was consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to initiate a new proceeding regarding the equity return and other issues involving the operating companies' formula rate contracts. The motion was submitted pursuant to review procedures applicable to these contracts, and would be applicable to billings under such contracts on and after January 1, 1999.
Southern Company Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered into a settlement agreement related to tax issues for the years 1984 through 1987. The agreement received final approval by the Joint Congressional Committee on Taxation in June 1998 and as a result, Alabama Power and Georgia Power recognized interest income in 1998 of $14 million and $69 million, respectively. The refund by the IRS has been received and this matter is now concluded.
Mobile Energy Services Petition for Bankruptcy
On January 14, 1999, Mobile Energy Services Company, LLC (MESC) -- an indirect subsidiary of Southern Company -- filed a petition for Chapter 11 bankruptcy relief in the U.S. Bankruptcy Court for the Southern District of Alabama. MESC 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. This action is in response to Kimberly-Clark Tissue Company's announcement in May 1998 of plans to close its pulp mill, effective September 1, 1999. As a part of the filing, MESC also is seeking payment for damages from Kimberly-Clark Tissue Company. MESC will continue to operate the facility as debtors-in possession, subject to the supervision and orders of the bankruptcy court. A reorganization plan has not yet been filed by MESC.
Southern Company's equity investment in MESC was $20 million and MESC's total assets were $392 million at December 31, 1998. MESC contributed $4 million and $6 million to consolidated net income in 1998 and 1997, respectively. At December 31, 1998, MESC had senior debt outstanding of $234 million of first mortgage bonds and $85 million related to tax-exempt bonds. MESC paid in January 1999 its regular semi-annual payment of $17 million to its bondholders. 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 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.
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In June 1995, the APSC issued a rate order granting Alabama Power's request for gradual adjustments to move toward parity among customer classes. This order also calls for 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.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
Georgia Power Investment in Rocky Mountain
In its 1985 financing order, the GPSC concluded that completion of the Rocky Mountain pumped storage hydroelectric plant in 1991 as then planned was not economically justifiable and reasonable and withheld authorization for Georgia Power to spend funds from approved securities issuances on that plant. In 1988, Georgia Power and Oglethorpe Power Corporation (OPC) entered into a joint ownership agreement for OPC to assume responsibility for the construction and operation of the plant. The plant went into commercial operation in 1995.
In June 1996, the GPSC initiated a review of this plant. On January 14, 1998, the GPSC ordered that Georgia Power be allowed to include approximately $108 million of its $142 million investment in rate base as of December 31, 1998. In December 1998, Georgia Power recorded a write down of $34 million -- $21 million after taxes -- on its investment in Rocky Mountain as a result of the GPSC's 1998 retail rate order discussed later. This matter is now concluded.
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 new three-year rate order for Georgia Power. 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 will be decreased by $262 million effective January 1, 1999, and by an additional $24 million effective January 1, 2000. The order further provides for $85 million each year, and up to an additional $50 million annually in 2000 and 2001 of any earnings in excess of the 12.5 percent return, to be applied to accelerated amortization or depreciation of assets. Two-thirds of any additional earnings in excess of the 12.5 percent return in any year will be applied to rate reductions and the remaining one-third retained by Georgia Power. During the term of the order, Georgia Power will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. Georgia Power is required to file a general rate case on July 1, 2001. At that time, the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued.
4. CONSTRUCTION PROGRAM
Southern Company is engaged in continuous construction programs, currently estimated to total some $2.6 billion in 1999, $2.1 billion in 2000, and $2.1 billion in 2001. 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, 1998, significant purchase commitments were outstanding in connection with the construction program. The operating companies have approximately 2,700 megawatts of combined cycle generation scheduled to be placed in service by 2001. Southern Energy has under construction some 1,300 megawatts of owned capacity. In addition, significant construction will continue related to transmission and distribution facilities and the upgrading of generating plants.
See Management's Discussion and Analysis under "Environmental Matters" for information on the impact of the Clean Air Act Amendments of 1990 and other environmental matters.
5. INVESTMENTS, FINANCING, AND COMMITMENTS
Investments
In December 1998, Southern Energy designed and implemented a plan to dispose of its Argentinean and Chilean investments by December 31, 1999. As a result,
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Southern Energy recorded an after-tax write down of approximately $200 million in 1998 to reflect the difference between the carrying value of these assets and the estimated fair value of the businesses. Southern Energy estimated the fair value of the businesses held for sale based upon bids received from prospective buyers, if available, or the discounted expected future cash flows to be generated by the assets. The adjusted carrying value of these assets held for disposal at December 31, 1998 was $90 million. These assets impacted the Consolidated Statements of Income as follows:
Operating Operating Consolidated Year Revenues Income Net Income - - - - - - - ---- --------------------------------------------- 1998 $180 $39 $ 5 1997 180 38 5 1996 157 20 (5)
Depreciation expense was suspended beginning January 1999, and the after-tax amount of depreciation recorded in 1998 was $16 million. Southern Energy is actively pursuing and/or negotiating with potential buyers. However at this time, a definitive agreement has not been entered into.
Southern Energy acquired $670 million of generating assets in 1998 and sold an additional 26 percent interest in its United Kingdom subsidiary for $170 million. In late 1998, Southern Energy announced plans to acquire $801 million and $480 million of generating assets in California and New York, respectively. These transactions are expected to close in 1999. At December 31, 1998, Southern Energy's total assets amounted to $12 billion.
Financing
The amount and timing of additional equity capital to be raised in 1999 -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. Equity capital can be provided from any combination of public offerings, private placements, or the company's stock plans.
The operating companies' construction programs are expected to be financed primarily from internal sources. Short-term debt is often utilized and the amounts available are discussed below. The companies may issue additional long-term debt and preferred securities primarily for debt maturities and for redeeming higher-cost securities if market conditions permit.
Bank Credit Arrangements
At the beginning of 1999, unused credit arrangements with banks totaled $4.6 billion, of which $2.7 billion expires during 1999, $304 million during 2000 to 2001, $1.0 billion during 2002, and $593 million during 2003 and 2004. The following table outlines the credit arrangements by company:
Amount of Credit ----------------------------------------- Expires -------------------- 2000 & Company Total Unused 1999 beyond - - - - - - - -------- ----------------------------------------- (in millions) Alabama Power $ 758 $ 758 $ 678 $ 80 Georgia Power 1,252 1,252 722 530 Gulf Power 103 97 97 - Mississippi Power 96 76 56 20 Savannah Electric 61 61 41 20 Southern Company 2,000 2,000 1,000 1,000 Southern Energy 907 340 71 269 Other 70 54 54 - - - - - - - - ----------------------------------------------------------------- Total $5,247 $4,638 $2,719 $1,919 =================================================================
Approximately $2.0 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 $4.6 billion in unused credit, $1.7 billion and $1.0 billion are syndicated credit arrangements of Southern Company and Georgia Power, respectively. These facilities also require the payment of agent fees.
A portion of the $4.6 billion unused credit with banks is allocated to provide liquidity support to the companies' variable rate pollution control bonds. At December 31, 1998, the amount of the credit lines allocated for this purpose was $1.4 billion.
In addition, the companies from time to time borrow under uncommitted lines of credit with banks. Also, Southern Company, Alabama Power, Georgia Power, and Southern Energy borrow through commercial paper programs that have the liquidity support of committed bank credit arrangements.
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
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, 1998, were as follows: Purchased Year Fuel Power - - - - - - - ----- ---------------------------- (in millions) 1999 $1,674 $ 161 2000 1,248 168 2001 1,048 170 2002 860 173 2003 824 177 2004 and thereafter 3,464 1,522 - - - - - - - ---------------------------------------------------------------- Total commitments $9,118 $2,371 ================================================================
Operating Leases
Southern Company has operating lease agreements with various terms and expiration dates. These expenses totaled $50 million, $33 million, and $25 million for 1998, 1997, and 1996, respectively. At December 31, 1998, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts - - - - - - - ----- --------- (in millions) 1999 $ 46 2000 39 2001 31 2002 30 2003 29 2004 and thereafter 304 - - - - - - - --------------------------------------------------------------- Total minimum payments $479 ===============================================================
Energy Trading and Marketing Commitments
In January 1998, Southern Energy and Vastar combined their energy trading and marketing activities to form a joint venture, Southern Company Energy Marketing (SCEM). Southern Company and Vastar have separately made guarantees to certain counterparties regarding performance of contractual commitments by the joint venture. Southern Company and Vastar have agreed to indemnify each other against losses under such guarantees in proportion to their respective ownership shares of SCEM. Southern Company's ownership interest is 60 percent. At December 31, 1998, outstanding guarantees related to the estimated fair value of net contractual commitments were approximately $152 million. Based upon the SCEM's statistical analysis of its credit risk, Southern Company's potential exposure under these contractual commitments would not materially differ from the estimated fair value. SCEM's gross revenues and cost of sales for 1998 were $9.2 billion and $9.1 billion, respectively.
Southern Energy has guaranteed certain minimum annual cash distributions, subject to exclusions, payable by SCEM to Vastar. These distributions before adjustments total $105 million for the period 1999-2002.
Vastar has the right -- exercisable in the period from December 1, 2002 through the first business day of 2003 -- to sell its remaining interest in SCEM to Southern Energy. The price will range from $130 million to $210 million depending on the interest owned by Vastar at that time, plus certain other contractual considerations.
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.
6. FACILITY SALES AND 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, together with transmission facilities, jointly with OPC, the Municipal Electric Authority of Georgia, and the city of Dalton, Georgia. In addition, Georgia Power has joint ownership agreements with OPC for
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
the Rocky Mountain project and with Florida Power Corporation (FPC) for a combustion turbine unit at Intercession City, Florida.
At December 31, 1998, 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% $3,296 $1,514 Plant Hatch (nuclear) 50.1 840 538 Plant Miller (coal) Units 1 and 2 91.8 717 330 Plant Scherer (coal) Units 1 and 2 8.4 112 48 Plant Wansley (coal) 53.5 298 141 Rocky Mountain (pumped storage) 25.4 169 61 Intercession City (combustion turbine) 33.3 12 * - - - - - - - ----------------------------------------------------------------- *Less than $1 million.
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.
7. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. These agreements -- 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 capacity revenues amounted to $196 million in 1998, $203 million in 1997, and $217 million in 1996.
Unit power from specific generating plants is currently being sold to Florida Power & Light Company (FP&L), FPC, Jacksonville Electric Authority (JEA), and the city of Tallahassee, Florida. Under these agreements, approximately 1,600 megawatts of capacity is scheduled to be sold in 1999. Thereafter, these sales will decline to some 1,500 megawatts and remain at that approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after 1999 with a minimum of three years notice -- until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets and liabilities were $1.0 billion and $715 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. 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 income tax provisions are as follows:
1998 1997 1996 - - - - - - - --------------------------------------------------------------- (in millions) Total provision for income taxes: Federal -- Currently payable $ 451 $ 547 $569 Deferred -- current year 195 188 116 -- reversal of prior years (208) (160) (74) - - - - - - - --------------------------------------------------------------- 438 575 611 - - - - - - - --------------------------------------------------------------- State -- Currently payable 106 104 82 Deferred -- current year 28 15 23 -- reversal of prior years (31) (19) (9) - - - - - - - --------------------------------------------------------------- 103 100 96 - - - - - - - --------------------------------------------------------------- International -- Windfall profits tax assessed in United Kingdom - 148 - Other 8 16 50 - - - - - - - --------------------------------------------------------------- Total 549 839 757 Less income taxes charged (credited) to other income (8) 114 10 - - - - - - - --------------------------------------------------------------- Total income taxes charged to operations $ 557 $ 725 $747 ===============================================================
The first half of the windfall profits tax assessed in the United Kingdom was paid in December 1997, and the remainder in December 1998.
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $3,315 $3,345 Property basis differences 1,667 1,756 Other 403 269 - - - - - - - --------------------------------------------------------------- Total 5,385 5,370 - - - - - - - --------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 104 108 Other property basis differences 239 245 Deferred costs 132 116 Pension and other benefits 79 72 Other 293 197 - - - - - - - --------------------------------------------------------------- Total 847 738 - - - - - - - --------------------------------------------------------------- Net deferred tax liabilities 4,538 4,632 Portion included in current assets, net (57) 18 - - - - - - - --------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheets $4,481 $4,650 ===============================================================
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 Consolidated Statements of Income. Credits amortized in this manner amounted to $38 million in 1998, $30 million in 1997, and $33 million in 1996. At December 31, 1998, 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:
1998 1997 1996 - - - - - - - ---------------------------------------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 4.1 3.4 3.2 Non-deductible book depreciation 4.1 2.3 1.8 International tax credits (6.4) - - Windfall profits tax - 8.0 - Difference in prior years' deferred and current tax rate (1.3) (1.5) (1.0) Other (1.8) (1.9) (0.5) - - - - - - - ---------------------------------------------------------------- Effective income tax rate 33.7% 45.3% 38.5% ================================================================
Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
The undistributed earnings of certain foreign subsidiaries aggregated $251 million as of December 31, 1998, which, under existing tax law, will not be subject to U.S. income tax until distributed. Because the earnings have been or are intended to be indefinitely reinvested, no provision has been made for any taxes that may be applicable. It is not practicable to estimate the amount of unrecognized deferred U.S. income taxes on undistributed earnings.
9. COMMON STOCK
Treasury Stock
In July 1998, Southern Company's Board of Directors authorized the company to make open market purchases of its common stock in an aggregate amount not to exceed $300 million through March 31, 1999. The purpose of the program is to provide shares of common stock for the purchase requirements of Southern Company's various stockholder, employee, and outside director stock purchase plans. Under the program, 4.4 million shares have been repurchased and 2.4 million shares were reissued through December 31, 1998.
Shares Reserved
At December 31, 1998, a total of 45 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
As of December 31, 1998, 302 current and former employees participated in the Performance Stock Plan. The maximum number of shares of common stock that may be issued under the new 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 four 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
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Company Board of Directors in accordance with the plan. Stock option activity in 1997 and 1998 for the plan is summarized below:
Shares Average Subject Option Price To Option Per Share - - - - - - - -------------------------------------------------------------- Balance at December 31, 1996 3,825,164 $21.11 Options granted 1,776,094 21.25 Options canceled (64,326) 22.10 Options exercised (137,426) 19.72 - - - - - - - -------------------------------------------------------------- Balance at December 31, 1997 5,399,506 21.15 Options granted 1,659,519 27.03 Options canceled (23,495) 23.18 Options exercised (603,195) 20.92 - - - - - - - -------------------------------------------------------------- Balance at December 31, 1998 6,432,335 $23.92 ==============================================================
Shares reserved for future grants: At December 31, 1996 668,062 At December 31, 1997 38,241,376 At December 31, 1998 36,598,001 - - - - - - - -------------------------------------------------------------- Options exercisable: At December 31, 1997 2,006,511 At December 31, 1998 2,653,591 - - - - - - - --------------------------------------------------------------
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.
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 less than 1 cent per share and is not significant to the consolidated financial statements.
Earnings Per Share
FASB Statement No. 128, Earnings per Share simplifies the methodology for computing both basic and diluted earnings per share. The only difference in the two methods for computing Southern Company's per share amounts is attributable to outstanding options under the Performance Stock Plan. The effect of the stock options was determined using the treasury stock method. Consolidated net income as reported was not affected. Shares used to compute diluted earnings per share are as follows:
Average Common Stock Shares -------------------------------- 1998 1997 1996 - - - - - - - --------------------------------------------------------------- (in thousands) As reported shares 696,944 685,033 672,590 Effect of options 739 201 200 - - - - - - - --------------------------------------------------------------- Diluted shares 697,683 685,234 672,790 ===============================================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 1998, consolidated retained earnings included $3.4 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.
10. 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, 1998, capital securities of $950 million and preferred securities of $1.2 billion were outstanding. Southern Company guarantees the notes related to $950 million of capital securities issued on its behalf.
11. 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:
1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Bond improvement fund requirements $ 23 $ 38 Less: Portion to be satisfied by certifying property additions 14 3 - - - - - - - --------------------------------------------------------------- Cash requirements 9 35 First mortgage bond maturities and redemptions 868 349 Other long-term debt maturities 563 400 - - - - - - - --------------------------------------------------------------- Total $1,440 $784 ===============================================================
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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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
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 operating companies have authenticated and delivered to trustees a like principal amount of first mortgage bonds as security for obligations under installment sale or loan agreements. The principal and interest on the first mortgage bonds will be payable only in the event of default under the agreements.
Improvement fund requirements and/or serial maturities through 2003 applicable to other long-term debt are as follows: $563 million in 1999; $385 million in 2000; $433 million in 2001; $1,035 million in 2002; and $387 million in 2003.
12. 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 $9.7 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.
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 17 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 $21 million and $25 million, respectively.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies issued or renewed on or after April 2, 1991, 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.
13. PURCHASE METHOD ACQUISITION
Southern Energy completed in 1997 the acquisition of a 100 percent interest in Consolidated Electric Power Asia (CEPA) for a total net investment of some $2.1 billion. CEPA is the largest independent power producer in Asia. The CEPA
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
acquisition has been accounted for under the purchase method of accounting. The acquisition cost exceeded the fair market value of net assets by approximately $1.6 billion. This amount is considered goodwill and is being amortized on a straight-line basis over 40 years.
CEPA has been included in the consolidated financial statements since January 29, 1997. The following unaudited pro forma results of operations have been prepared assuming the acquisition of CEPA, effective January 1, 1996. The pro forma results assume acquisition financing of $716 million of short-term borrowings, $792 million of long-term notes, and $600 million of capital securities. Southern Company's assumed effective composite interest rate on these obligations for each period was 6.82 percent.
These unaudited pro forma results are not necessarily indicative of the actual results that would have been realized had the acquisition occurred on the assumed dates, nor are they necessarily indicative of future results. Pro forma operating results are for information purposes only and are as follows:
14. SEGMENT AND RELATED INFORMATION
Effective December 31, 1997, Southern Company adopted FASB Statement No. 131, Disclosure About Segments of an Enterprise and Related Information. Southern Company's principal business segment -- or its traditional core business -- is the five regulated electric utility operating companies that provide electric service in four southeastern states. The other reportable business segment is non-traditional energy services to retail and wholesale customers provided by Southern Energy, which develops and manages electricity and other energy-related projects both in the United States and abroad including domestic energy trading and marketing for 1997 and 1996. Intersegment revenues are not material. Financial data for business segments, products and services, and geographic areas are as follows:
Business Segments
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NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
11-43
NOTES (continued) Southern Company and Subsidiary Companies 1998 Annual Report
Products and Services
11-44
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998 Southern Company and Subsidiary 1998 Annual Report
11-45
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998 (continued) Southern Company and Subsidiary Companies 1998 Annual Report
11-46A
11-46B
II-47
11-48A
11-48B
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-49
MANAGEMENT'S REPORT Alabama Power Company 1998 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 generally accepted accounting principles appropriate in the circumstances 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 books and 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 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 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 generally accepted accounting principles.
/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
February 10, 1999
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary of Southern Company) as of December 31, 1998 and 1997, and the related statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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 ade 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-61 through II-79) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Arthur Andersen LLP
Birmingham, Alabama February 10, 1999
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1998 net income after dividends on preferred stock was $377 million, representing a $1.3 million (0.3 percent) increase from the prior year. This improvement can be attributed primarily to increased retail energy sales as a result of hot weather in the second quarter of 1998, compared to very mild weather for the same period in 1997 and a strong economy in the Company's service territory. However, earnings were offset by an increase in non-fuel operation and maintenance expenses and an increase in the amortization of debt discount, premium, and expense, net pursuant to an Alabama Public Service Commission (APSC) order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details.
In 1997, earnings were $376 million, representing a 1.2 percent increase from the prior year. This increase was due to lower non-fuel related operating expenses. Despite the mild weather experienced during 1997, retail kilowatt-hour (KWH) sales increased approximately 2 percent. However, the expected net income effect was offset by the effect of reductions in certain industrial and commercial prices.
The return on average common equity for 1998 was 13.63 percent compared to 13.76 percent in 1997, and 13.75 percent in 1996.
Revenues
Operating revenues for 1998 were $3.4 billion, reflecting a 7.5 percent increase from 1997. The following table summarizes the principal factors that affected operating revenues for the past three years:
Increase (Decrease) From Prior Year ----------------------------------------- 1998 1997 1996 ----------------------------------------- (in thousands) Retail -- Growth and price change $ 75,642 $ 33,813 $ 42,385 Weather 55,282 (22,973) (29,660) Fuel cost recovery and other 138,944 31,353 (30,846)
- - - - - - - ------------------------------------------------------------------- Total retail 269,868 42,193 (18,121) ------------------------------------------------------------------ Sales for resale -- Non-affiliates 17,950 39,354 21,529 Affiliates (58,233) (54,825) 88,890 ------------------------------------------------------------------ Total sales for resale (40,283) (15,471) 110,419
Other operating revenues 7,677 1,614 3,703 - - - - - - - ------------------------------------------------------------------- Total operating revenues $237,262 $ 28,336 $ 96,001 ---------------------------------------------------------------- Percent change 7.5% 0.9% 3.2% ===================================================================
Retail revenues of $2.8 billion in 1998 increased $270 million (10.7 percent) from the prior year, compared with an increase of $42 million (1.7 percent) in 1997. The predominant factors causing the rise in revenues in 1998 were the positive impact of weather on energy sales, continued growth throughout the state, and increased fuel revenues. Fuel revenues were higher in the current year due to higher fuel costs and an increase in purchased power.
Retail revenues in 1997 increased $42 million (1.7 percent) over 1996. The primary reason for this increase was an increase in fuel revenues due to slightly higher generation and higher fuel costs in 1997 as compared to 1996. Fuel revenues generally represent the direct recovery of fuel expense, including the fuel component of purchased energy, and therefore have no effect on net income.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
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. These capacity and energy components were:
1998 1997 1996 ------------------------------------------- (in thousands)
Capacity $141,814 $136,248 $150,797 Energy 118,252 134,498 107,996 ------------------------------------------------------------ Total $260,066 $270,746 $258,793 =============================================================
Capacity revenues from non-affiliates increased 4.1 percent in 1998 compared to the prior year. Capacity revenues from non-affiliates in 1997 decreased 9.6 percent compared to 1996 primarily due to a one-time unit power sales adjustment in 1997.
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.
KWH sales for 1998 and the percent change by year were as follows:
KWH Percent Change ------------------------------------------- 1998 1998 1997 1996 ------------------------------------------- (millions)
Residential 15,795 10.2% (1.8)% 1.5% Commercial* 11,905 5.1 3.9 8.6 Industrial* 21,585 4.2 3.6 0.7 Other 196 8.3 (6.3) 3.1 ----------- Total retail 49,481 6.2 1.9 2.7 Sales for resale - Non-affiliates 11,841 (3.2) 29.9 18.0 Affiliates 5,976 (33.5) (12.6) 53.5 ----------- Total 67,298 (0.9)% 3.7% 10.5% ================================================================== *The KWH sales for 1996 reflect a reclassification of approximately 200 customers from industrial to commercial, which resulted in a shift of 473 million KWH. Absent the reclassification, the percentage change in KWH sales for commercial and industrial would have been 3.9% and 3.1%, respectively.
The increases in 1998 and 1997 retail energy sales were primarily due to the strength of business and economic conditions in the Company's service area. In 1998, residential energy sales experienced a 10.2 percent increase over the prior year primarily as a result of hot weather in the second quarter, compared to very mild weather in the second quarter of 1997. Assuming normal weather, sales to retail customers are projected to grow approximately 2.3 percent annually on average during 1999 through 2003.
Expenses
Total operating expenses of $2.7 billion for 1998 were up $207 million or 8.2 percent compared with 1997. This increase was mainly due to a $107 million increase in purchased power expenses, accompanied by a $58 million increase in maintenance expense.
Total operating expenses of $2.5 billion for 1997 were up $18 million or 0.7 percent compared with 1996. This increase was primarily due to a $19 million increase in fuel costs and a $10 million increase in epreciation and amortization expense. These increases were somewhat offset by a $16 million decrease in maintenance 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:
-------------------------- 1998 1997 1996 -------------------------- Total generation (billions of KWHs) 63 65 65 Sources of generation (percent) -- Coal 72 72 72 Nuclear 18 20 20 Hydro 8 8 8 Oil & Gas 2 * * Average cost of fuel per net KWH generated (cents) -- 1.54 1.49 1.46 ============================================================== * Not meaningful because of minimal generation from fuel source.
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
Total fuel and purchased power costs of $1.1 billion in 1998 increased $111 million (11 percent) over 1997 primarily due to lower levels of nuclear and hydro generation, which were replaced by the use of peaking units and purchased power.
Fuel and purchased power costs in 1997 increased $27 million (3 percent) over 1996 due primarily to slightly higher generation and fuel costs in 1997.
Purchased power consists primarily of purchases from the affiliates of the Southern electric system. 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. Total KWH purchases increased 24.5 percent from the prior year.
The 23.8 percent increase in maintenance expense in 1998 as compared to 1997 is attributable to (i) an increase in the maintenance of overhead lines, (ii) the write-off of obsolete steam and nuclear generating plant inventory, and (iii) additional accruals to partially replenish the natural disaster reserve. The 6.1 percent decrease in maintenance expenses in 1997 is attributable primarily to a decrease in distribution expenses.
Depreciation and amortization expense increased 2.6 percent in 1998 and 3.2 percent in 1997. These increases reflect additions to utility plant.
Total net interest and other charges increased $55.7 million (22 percent) in 1998. This increase results primarily from an increase in the amortization of debt discount, premium, and expense, net pursuant to an APSC order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details. Total net interest and other charges increased $25.4 million (11.2 percent) in 1997 primarily due to an increase in company obligated mandatorily redeemable preferred securities outstanding. This increase was offset by a $12 million (45.2 percent) decrease in dividends on preferred stock.
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 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 its traditional service area located in the 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 in the near term will depend upon growth in electric sales, which are 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.
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 excess 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 business in the Southeastern power markets.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
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 various restructuring and competition initiatives have been or are being discussed in Alabama, Florida, Georgia, and Mississippi, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. 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 of the Company. The Company is attempting to minimize or reduce stranded 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, unless the Company remains a low-cost producer and provides quality service, the Company's retail energy sales growth could be limited, and this could significantly erode earnings.
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. In June 1995, the APSC issued an order granting the Company's request for gradual adjustments to move toward parity among customer classes. This order also calls for a moratorium on any periodic retail rate increases (but not decreases) until 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. See Note 3 to the financial statements for information about this and other matters.
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 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 Financial Accounting Standards Board (FASB) has decided to review 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 "Regulatory Assets and Liabilities" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s shortened the year portion of date entries to just two digits. Computers assumed, in effect, that all years began with "19." This practice was widely adopted and hard-coded into computer chips and processors found in some equipment. This approach, intended to save processing time and storage space, was used until the mid-1990s. Unless corrected before the Year 2000, affected software systems and devices containing a chip or microprocessor with date and time functions could incorrectly process dates or the systems may cease to function.
The Company depends on complex computer systems for many aspects of its operations, which include generation, transmission, and distribution of electricity, as well as other business support activities. The Company's goal is to have critical devices or software that are required to maintain operations to be Year 2000 ready by June 1999. Year 2000 ready means that a system or application is determined suitable for continued use through the Year 2000 and beyond. Critical systems include, but are not limited to, reactor control systems, safe shutdown systems, turbine generator systems, control center computer systems, customer service systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000 challenge and has dedicated what it believes to be adequate resources to address the issue. The Millennium Project is a team of employees, IBM consultants, and other contractors whose progress is reviewed on a monthly basis by a steering committee of Southern Company executives.
The Company's Year 2000 program was divided into two phases. Phase I began in 1996 and consisted of identifying and assessing corporate assets related to software systems and devices that contain a computer chip or clock. The first phase was completed in June 1997. Phase 2 consists of testing and remediating high priority systems and devices. Also, contingency planning is included in this phase. Completion of Phase 2 is targeted for June 1999. The Millennium Project will continue to monitor the affected computer systems, devices, and applications into the Year 2000.
The Southern Company has completed more than 70 percent of the activities contained in its work plan. The percentage of completion and projected completion by function are as follows:
- - - - - - - ------------------------------------------------------------------------------ Work Plan ------------------------------------------------------ Remediation Project Inventory Assessment Testing Completion - - - - - - - ------------------------------------------------------------------------------ Generation 100% 100% 70% 6/99 - - - - - - - ------------------------------------------------------------------------------ Energy Management 100 100 90 6/99 - - - - - - - ------------------------------------------------------------------------------ Transmission and Distribution 100 100 100 1/99 - - - - - - - ------------------------------------------------------------------------------ Telecommunications 100 100 50 6/99 - - - - - - - ------------------------------------------------------------------------------ Corporate Applications 100 100 90 3/99 - - - - - - - ------------------------------------------------------------------------------
Year 2000 Costs
Current projected total costs for Year 2000 readiness, including the Company's share of costs of Southern Nuclear Operating Company, are approximately $36 million. These costs include labor necessary to identify, test, and renovate affected devices and systems. From its inception through December 31, 1998, the Year 2000 program costs, recognized primarily as expense, amounted to $21 million.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of service interruptions related to the Year 2000. The Company believes, based on current tests, that the system can provide customers with electricity. These tests increase confidence, but do not guarantee error-free operation. The Company is taking what it believes to be prudent steps to prepare for the Year 2000, and it expects any interruptions in service that may occur within the service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe than the scenarios that its electric system is routinely prepared to handle. The most likely worst case scenario consists of the service loss of one of the largest generating units and/or the service loss of any single bulk transmission
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
element in its service territory. The Company has followed a proven methodology for identifying and assessing software and devices containing potential Year 2000 challenges. Remediation and testing of those devices are in progress. Following risk assessment, the Company is preparing contingency plans as appropriate and is participating in North American Electric Reliability Council-coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third parties that provide goods and services crucial to the Company's operations. Among such critical third parties are fuel, transportation, telecommunications, water, chemical, and other suppliers. Contingency plans based on the assessment of each third party's ability to continue supplying critical goods and services to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical demand by customers because of their Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled at developing and using contingency plans in unusual circumstances. As part of Year 2000 business continuity and contingency planning, the Company is drawing on that experience to make risk assessments and is developing additional plans to deal specifically with situations that could arise relative to Year 2000 challenges. The Company is identifying critical operational locations, and key employees will be on duty at those locations during the Year 2000 transition. In September 1999, drills are scheduled to be conducted to test contingency plans. Because of the level of detail of the contingency planning process, management feels that the contingency plans will keep any service interruptions that may occur within the service territory isolated and short in duration.
Exposure to Market Risk
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 statement as incurred. At December 31, 1998, 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, 1998, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by the year 2000. This statement establishes accounting and reporting standards for derivative instruments - including certain derivative instruments embedded in other contracts - and for hedging activities. The Company has not yet quantified the impact of adopting this statement on its financial statements; however, the adoption could increase volatility in earnings.
In March 1998, the American Institute of Certified Public Accountants (AICPA) issued a new Statement of Position, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement requires capitalization of certain costs of internal-use software. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the Costs of Start-up Activities. This statement requires that the costs of start-up activities and organizational costs be expensed as incurred. Any of these costs previously capitalized by a company must be written off in the year of adoption. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The EITF requires that energy trading contracts must be marked to market through the income statement, with gains and losses reflected rather than revenues and purchased power. Energy trading contracts are defined as energy contracts entered into with the objective of generating profits on or from exposure to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
shifts or changes in market prices. The Company adopted the required accounting in January 1999, and it is not expected to have a material impact on the financial statements.
FINANCIAL CONDITION
Overview
The Company's financial condition remained stable in 1998. 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 $610 million in 1998. The majority of funds needed for gross property additions for the last several years has 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 42.4 percent in 1998, compared with 44.7 percent in 1997, and 45.3 percent in 1996.
During 1998, the Company issued $1.4 billion of senior notes, the proceeds of which were used primarily to redeem first mortgage bonds and repay short-term indebtedness. Additionally in 1998, the Company redeemed $8 million of preferred stock and issued an additional $200 million.
Capital Requirements
Capital expenditures are estimated to be $875 million for 1999, $653 million for 2000, and $668 million for 2001. The total is $2.2 billion for the three years. Included in these estimates are the following: the Company will replace all six steam generators at Plant Farley at a total cost of approximately $234 million. Additionally, the Company plans to construct and install 1,075 megawatts of new generating capacity and associated substation facilities at Plant Barry. The projected capital expenditures for this project amount to approximately $384 million.
Actual capital costs may vary from estimates because of factors such as changes in business conditions; revised load growth projections; changes in environmental regulations; changes in the existing nuclear plant 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.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $270 million will be required by the end of 2000 for maturities of first mortgage bonds. Also, 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 was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law - significantly impacted the operating companies of Southern Company, including Alabama Power. 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 initially affected 28 generating units of Southern Company. As a result of Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
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.
For Phase II sulfur dioxide compliance, the Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as necessary to meet Phase II limits. Current
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
compliance strategy for Phase II could require total estimated construction expenditures of approximately $38 million, of which $19 million remains to be spent.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. In September 1998, the EPA issued the final regional nitrogen oxide rules to the states for implementation. The states have one year to adopt and implement the new rules. The final rules affect 22 states including Alabama. The EPA rules are being challenged in the courts by several states and industry groups. Implementation of the final state rules could require substantial further reductions in nitrogen oxide emissions from fossil-fired generating facilities and other industry in these states. Implementation of the standards could result in significant additional compliance costs and capital expenditures that cannot be determined until the results of legal challenges are known and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: nitrogen oxide emission control strategies for ozone nonattainment areas; additional controls for hazardous air pollutant emissions; control strategies to reduce regional haze; and hazardous waste disposal requirements. The impact of 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. 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.
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 Southern Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The 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. In this regard, the Company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur. To issue additional debt and equity securities, the Company must comply with certain earnings coverage requirements designated in its mortgage indenture and corporate charter. The Company's coverages are at a level that would permit any necessary amount of security sales at current interest and dividend rates.
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."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1998 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 1998 Annual Report contains forward-looking and historical information. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking information; accordingly, there can be no assurance that such indicated results will be realized. These factors include legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry; 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 internal restructuring -- that may be pursued by Southern Company; state and federal rate regulation; Year 2000 issues; changes in or application of environmental and other laws and regulations to which the Company is subject; political, legal and economic conditions and developments; financial market conditions and the results of financing efforts; changes in commodity prices and interest rates; weather and other natural phenomena; and other factors discussed in the reports--including Form 10-K--filed from time to time by the Company with the Securities and Exchange Commission.
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STATEMENTS OF INCOME For the Years Ended December 31, 1998, 1997, and 1996 Alabama Power Company 1998 Annual Report
STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1998, 1997, and 1996 Alabama Power Company 1998 Annual Report
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BALANCE SHEETS At December 31, 1998 and 1997 Alabama Power Company 1998 Annual Report
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NOTES TO FINANCIAL STATEMENTS Alabama Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, Southern Company Services (SCS), a system service company, Southern Communications Services (Southern LINC), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The operating companies (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four southeastern states. Contracts among the companies--dealing with 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). 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 Energy designs, builds, owns and operates power production and delivery facilities and provides a broad range of energy related services in the United States and international markets. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Company Energy Solutions develops new business opportunities related to energy products and services.
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 generally accepted accounting principles (GAAP) and complies with the accounting policies and practices prescribed by the respective regulatory commissions. The preparation of financial statements in conformity with GAAP 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.
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:
1998 1997 ----------------------- (in thousands) Deferred income taxes $ 362,953 $ 384,549 Deferred income tax credits (315,735) (327,328) Premium on reacquired debt 83,440 81,417 Department of Energy assessments 31,088 34,416 Vacation pay 28,390 28,783 Natural disaster reserve (19,385) (22,416) Work force reduction costs 4,082 19,316 Other, net 46,672 59,726 - - - - - - - ---------------------------------------------------------------- Total $ 221,505 $ 258,463 ================================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statemen No. 71, the Company would be required to write off related net 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) Alabama Power Company 1998 Annual Report
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 by type of service were as follows:
1998 1997 1996 -------------------------------- (in millions) Retail $2,781 $2,511 $2,469 Non-affiliated wholesale 449 431 391 Other 53 45 44 - - - - - - - --------------------------------------------------------------- Total $3,283 $2,987 $2,904 - - - - - - - ---------------------------------------------------------------
The Company accrues revenues for services rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The Company's electric rates include provisions to adjust billings for fluctuations in fuel and the energy component of purchased power 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 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 $59 million in 1998, $68 million in 1997, and $64 million in 1996. 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 contracts, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient storage capacity currently is available to permit operation into 2009 and 2013 at Plant Farley units 1 and 2, respectively.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a Uranium Enrichment Decontamination and Decommissioning Fund, which is to be funded in part by a special assessment on utilities with nuclear plants. This 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 estimates its remaining liability at December 31, 1998, under this law to be approximately $31 million. 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 1998 and 3.3 percent in both 1997 and 1996. 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 decommissioning nuclear facilities and removal of other facilities.
Nuclear Regulatory Commission (NRC) regulations require 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.
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NOTES (continued) Alabama Power Company 1998 Annual Report
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 -- at December 31, 1998, 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 amounts expensed in 1998 and fund balance as of December 31, 1998 were:
(in millions) Amount expensed in 1998 $ 18 -------------------------------------------------------------
Accumulated provisions: Balance in external trust funds $ 232 Balance in internal reserves 42 ------------------------------------------------------------- Total $ 274 =============================================================
All of the Company's decommissioning costs are approved for ratemaking. Significant assumptions include an estimated inflation rate of 4.5 percent and an estimated trust earnings rate of 7.0 percent.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Allowance For Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rate used to determine the amount of allowance was 9.0 percent in 1998 and 5.8 percent in both 1997 and 1996. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 1.8 percent in 1998, 0.8 percent in 1997 and 1.1 percent in 1996.
Utility Plant
Utility plant 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.
Financial Instruments
The Company's only financial instruments for which the carrying amount did not approximate fair value at December 31 are as follows:
Carrying Fair Amount Value ------------------------- (in millions) Long-term debt: At December 31, 1998 $3,112 $3,195 At December 31, 1997 2,541 2,638 Preferred Securities: At December 31, 1998 297 307 At December 31, 1997 297 300 --------------------------------------------------------------
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NOTES (continued) Alabama Power Company 1998 Annual Report
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 September 1994, in response to a request by the Company, the APSC issued an order allowing the Company to establish a Natural Disaster Reserve. Regulatory treatment allows the Company to accrue $250 thousand per month, until the maximum accumulated provision of $32 million is attained. However, in December 1995, the APSC approved higher accruals to restore the reserve to its authorized level whenever the balance in the reserve declines below $22.4 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 eligiblefor such benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations or to the extent required by the APSC and FERC. In 1998, the Company adopted FASB Statement No. 132, Employers' Disclosure about Pensions and Other Postretirement Benefits. The measurement date is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were:
1998 1997 - - - - - - - --------------------------------------------------------------- Discount 6.75% 7.50% Annual salary increase 4.25 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 --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Balance at beginning of year $813 $814 Service cost 22 20 Interest cost 59 58 Benefits paid (51) (38) Actuarial (gain) loss and employee transfers 25 (41) - - - - - - - --------------------------------------------------------------- Balance at end of year $868 $813 ===============================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Balance at beginning of year $1,521 $1,334 Actual return on plan assets 9 250 Benefits paid (51) (38) Employee transfers (18) (25) - - - - - - - --------------------------------------------------------------- Balance at end of year $1,461 $1,521 ===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Funded status $ 593 $ 708 Unrecognized transition obligation (30) (35) Unrecognized prior service cost 39 43 Unrecognized net actuarial gain (433) (585) - - - - - - - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 169 $ 131 ===============================================================
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NOTES (continued) Alabama Power Company 1998 Annual Report
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - --------------------------------------------------------------- (in millions) Service cost $ 22 $ 20 $ 21 Interest cost 59 58 60 Expected return on plan assets (102) (95) (93) Recognized net actuarial gain (16) (13) (9) Net amortization (2) (2) (3) - - - - - - - --------------------------------------------------------------- Net pension cost (income) $ (39) $ (32) $ (24) ===============================================================
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Balance at beginning of year $252 $242 Service cost 5 4 Interest cost 19 18 Benefits paid (12) (8) Actuarial (gain) loss and employee transfers 14 (4) - - - - - - - --------------------------------------------------------------- Balance at end of year $278 $252 ===============================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Balance at beginning of year $125 $108 Actual return on plan assets 4 16 Employer contributions 20 9 Benefits Paid (12) (8) - - - - - - - --------------------------------------------------------------- Balance at end of year $137 $125 ===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows: 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Funded status $(141) $(127) Unrecognized transition obligation 57 61 Unrecognized net actuarial loss 22 3 Fourth quarter contributions 8 10 - - - - - - - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (54) $ (53) ===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - --------------------------------------------------------------- (in millions) Service cost $ 5 $ 4 $ 5 Interest cost 18 18 17 Expected return on plan assets (9) (7) (6) Recognized net gain - - 1 Net amortization 4 4 4 - - - - - - - ------------------------------------------------------ -------- Net postretirement cost $ 18 $ 19 $ 21 ===============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.30 percent for 1998, decreasing gradually to 4.75 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, 1998 as follows:
1 Percent 1 Percent Increase Decrease - - - - - - - --------------------------------------------------------------- (in millions) Benefit obligation $ 18 $ (15) Service and interest costs 2 (1) ===============================================================
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The costs related to these programs were $19.4 million, $33.0 million and $26.7 million for the years 1998, 1997 and 1996, respectively. In addition, certain costs of these programs were deferred and are being amortized in accordance with regulatory treatment. The unamortized balance of these costs was $4.1 million at December 31, 1998.
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Procedures
In November 1982, the APSC 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 in retail service. Both increases and decreases have been placed into effect since the adoption of these rates. The rate adjustment
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NOTES (continued) Alabama Power Company 1998 Annual Report
procedures allow a return on common equity range of 13.0 percent to 14.5 percent and limit increases or decreases in rates to 4 percent in any calendar year.
In June 1995, the APSC issued a rate order granting the Company's request for gradual adjustments to move toward parity among customer classes. This order also calls for 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 ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
Appliance Warranty Litigation
In 1996, a class action against the Company was filed charging the Company with fraud and non-compliance with regulatory statutes relating to the offer, sale, and financing of "extended service contracts" in connection with the sale of electric appliances. The plaintiffs seek damages in an unspecified amount. The Company has offered extended service agreements to its customers since January 1984, and approximately 175,000 extended service agreements could be involved in these proceedings. The trial court has granted partial summary judgment in favor of the plaintiffs. The Company has appealed this decision to the Supreme Court of Alabama. The final outcome of this case cannot now be determined.
Environmental Litigation
On November 30, 1998, total judgments of nearly $53 million were entered in favor of five plaintiffs against the Company and two large textile manufacturers. The plaintiffs alleged that the manufacturers had discharged certain polluting substances into a stream that empties into Lake Martin, a hydroelectric reservoir owned by the Company, and that such discharges had reduced the value of the plaintiffs' residential lots on Lake Martin. Of the total amount of the judgments, $155 thousand was compensatory damages and the remainder was punitive damages. The damages were assessed against all three defendants jointly. Post-trial motions have been filed, and, if relief is not granted at the trial court level, the Company will appeal these judgements to the Supreme Court of Alabama. While the Company believes that these judgments should be reversed or set aside, the final outcome of this matter cannot now be determined.
FERC Reviews Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of the administrative law judge's opinions in two proceedings in which the return on common equity component of formula rates contained in substantially all of the operating companies' wholesale power contracts was being challenged as unreasonably high. These orders resulted in no change in the wholesale power contracts that were the subject of such proceedings. The FERC also dismissed a complaint filed by three customers under long-term power sales agreements seeking to lower the equity return component in such agreements. These customers have filed applications for rehearing regarding each FERC order. In response to a requirement of the September 1998 FERC order, Southern Company filed a new equity return component on the long-term power sales contracts, to be effective January 5, 1999. The proposed equity return was lowered from 13.75 percent to 12.50 percent. If the filed equity return is approved, the estimated impact on the Company's revenues will be approximately $5 million annually. The FERC placed the new rates into effect, subject to refund. Also, this filing was consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to initiate a new proceeding regarding the equity return and other issues involving the Company's formula rate contracts. The motion was submitted pursuant to review procedures applicable to these contracts, and would be applicable to billings under such contracts on and after January 1, 1999.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered into a settlement agreement related to tax issues for the years 1984 through 1987. The agreement received final approval by the Joint Congressional
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NOTES (continued) Alabama Power Company 1998 Annual Report
Committee on Taxation in June 1998 and as a result, the Company recognized interest income in 1998 of $14 million. The refund by the IRS has been made and this matter is now concluded.
4. CAPITAL BUDGET
The Company's capital expenditures are currently estimated to total $875 million in 1999, $653 million in 2000, and $668 million in 2001. Included in these estimates are the following: the Company will replace all six steam generators at Plant Farley at a total cost of approximately $234 million. Additionally, the Company plans to construct and install 1,075 megawatts of new generating capacity and associated substation facilities at Plant Barry. The projected capital expenditures for this project amount to approximately $384 million.
The capital budget is subject to periodic review and revision, and actual capital costs incurred may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth projections; changes in environmental regulations; changes in the existing nuclear plant to meet new regulatory requirements; increasing costs of labor, equipment, and materials; and cost of capital.
In addition, significant construction will continue related to transmission and distribution facilities and the upgrading of generating plants.
5. FINANCING, INVESTMENT, AND COMMITMENTS
General
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.
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 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. In this regard, the Company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur. In order to issue additional debt and equity securities, the Company must comply with certain earnings coverage requirements designated in its mortgage indenture and corporate charter. The most restrictive of these provisions requires, for the issuance of additional first mortgage bonds, that before-income-tax earnings, as defined, cover pro forma annual interest charges on outstanding first mortgage bonds at least twice; and for the issuance of additional preferred stock, that gross income available for interest cover pro forma annual interest charges and preferred stock dividends at least one and one-half times. The Company's coverages are at a level that would permit any necessary amount of security sales at current interest and dividend rates.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $757.7 million (including $315 million of such lines under which are dedicated to funding purchase obligations relating to variable rate pollution control bonds). Of these lines, $677.7 million expire at various times during 1999 and $80 million expires in 2003. 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, 1998, 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.
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NOTES (continued) Alabama Power Company 1998 Annual Report
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, 1998, were as follows:
Year Amounts ---------------- (in millions) 1999 $ 825 2000 547 2001 497 2002 376 2003 381 2004 - 2014 2,417 - - - - - - - --------------------------------------------------------------- Total commitments $ 5,043 ===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $5.8 million in 1998, and $3.0 million each for 1997 and 1996. At December 31, 1998, estimated minimum rental commitments for noncancellable operating leases were as follows:
Year Amounts ---------------- (in millions) 1999 $ 11.4 2000 9.7 2001 7.3 2002 5.9 2003 5.7 2004 - 2018 51.4 - - - - - - - --------------------------------------------------------------- Total minimum payments $ 91.4 ===============================================================
6. 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 $74 million in 1998, $73 million in 1997 and $75 million in 1996, 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, 1998, the capitalization of SEGCO consisted of $49 million of equity and $70 million of long-term debt on which the annual interest requirement is $4.1 million. SEGCO paid dividends totaling $8.7 million in 1998, $10.6 million in 1997, and $10.1 million in 1996, of which one-half of each was paid to the Company. SEGCO's net income was $7.5 million, $8.5 million, and $7.7 million for 1998, 1997 and 1996, respectively.
The Company's percentage ownership and investment in jointly-owned generating plants at December 31, 1998, 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 $ 94 $ 42 Plant Miller Units 1 and 2 717 330 ----------------------------------------------------------
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NOTES (continued) Alabama Power Company 1998 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the operating affiliates 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 $142 million in 1998, $136 million in 1997, and $151 million in 1996.
Unit power from Plant Miller is being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority (JEA) and the City of Tallahassee, Florida. Under these agreements, approximately 1,200 megawatts of capacity are scheduled to be sold through 1999. Thereafter, these sales will remain at that approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after 1999 with a minimum of three years notice -- until the expiration of the contracts in 2010.
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 are returned to the Company. At December 31, 1998, $99.4 million of such bonds was held by the escrow agent under the contracts.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets and liabilities were $363 million and $316 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. 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:
1998 1997 1996 -------------------------------- (in thousands) Total provision for income taxes: Federal -- Currently payable $123,384 $197,159 $172,911 Deferred -- current year 59,162 32,884 (6,309) reversal of prior years 12,984 (44,300) 18,948 - - - - - - - ----------------------------------------------------------------- 195,530 185,743 185,550 - - - - - - - ----------------------------------------------------------------- State -- Currently payable 15,761 23,147 16,212 Deferred -- current year 4,811 1,409 697 reversal of prior years 2,473 (2,422) 3,249 - - - - - - - ----------------------------------------------------------------- 23,045 22,134 20,158 - - - - - - - ----------------------------------------------------------------- Total 218,575 207,877 205,708 Less income taxes credited to other income (6,347) (12,351) (22,400) - - - - - - - ----------------------------------------------------------------- Total income taxes charged to operations $224,922 $220,228 $228,108 =================================================================
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NOTES (continued) Alabama Power Company 1998 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
1998 1997 ------------------ (in millions) Deferred tax liabilities: Accelerated depreciat $ 861 $ 847 Property basis differences 435 463 Premium on reacquired debt 29 30 Pensions 50 20 Other 46 11 ---------------------------------------------------------------- Total 1,421 1,371 - - - - - - - ------------------------------------------------------------------ Deferred tax assets: Capacity prepayments 28 31 Other deferred costs 25 33 Postretirement benefits 20 18 Unbilled revenue 16 16 Other 56 66 Total 145 164 ---------------------------------------------------------------- Net deferred tax liabilities 1,276 1,207 Portion included in current assets (liabilities), net (73) (15) - - - - - - - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $ 1,203 $ 1,192 ================================================================
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 $11 million in 1998, 1997, and 1996. At December 31, 1998, 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:
1998 1997 1996 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.5 2.4 2.2 Non-deductible book depreciation 1.5 1.5 1.5 Differences in prior years' deferred and current tax rates (1.6) (2.3) (1.6) Other (1.6) (1.9) (3.0) - - - - - - - --------------------------------------------------------------- Effective income tax rate 35.8% 34.7% 34.1% ===============================================================
Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
9. 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
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. In February 1999, the Company issued $50 million of variable rate mandatorily redeemable preferred securities (Trust III), the initial distribution rate of which was 4.85 percent. The associated junior subordinated notes, in the amount of $51.6 million, will be due February 28, 2029.
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.
10. 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 $215.9 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.
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NOTES (continued) Alabama Power Company 1998 Annual Report
No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.
In 1997 and 1998, the Company issued unsecured senior notes. The 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 2003 are as follows: $1.0 million in 1999, $0.9 million in 2000, $0.8 million in 2001, $0.9 million in 2002 and $0.9 million in 2003.
11. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt and preferred stock due within one year at December 31 is as follows:
1998 1997 ------------------------ (in thousands) Bond improvement fund requirements $ - $18,450 First mortgage bond maturities and redemptions 470,000 55,895
Other long-term debt maturities (Note 10) 1,209 991 ------------------------------------------------------------- Total long-term debt due within one year 471,209 75,336 ------------------------------------------------------------- Preferred stock to be redeemed 50,000 - ------------------------------------------------------------- Total $521,209 $75,336 =============================================================
The annual first mortgage bond improvement fund requirement is 1 percent of the aggregate principal amount of bonds of each series authenticated, so long as a portion of that series is outstanding, and may be satisfied by the deposit of cash and/or reacquired bonds, the certification of unfunded property additions or a combination thereof. Scheduled maturities amount to $0.2 million in connection with pollution control bonds as a result of the redemption, over a five-year period, of the 7.25 percent series due 2003.
12. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (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 $9.7 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 cost of replacement power in an amount up to $3.5 million per week (starting 17 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 $21 million.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies issued or renewed on or after April 2, 1991, 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
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NOTES (continued) Alabama Power Company 1998 Annual Report
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.
13. 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, 1998, retained earnings of $796 million were restricted against the payment of cash dividends on common stock under terms of the mortgage indenture.
14. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1998 and 1997 are as follows:
Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock - - - - - - - -------------------- ----------------------------------------- (in thousands)
March 1998 $716,505 $130,735 $ 66,041 June 1998 863,715 178,722 94,750 September 1998 1,057,988 242,063 173,958 December 1998 748,165 105,519 42,474
March 1997 $704,768 $123,455 $ 57,807 June 1997 728,089 125,750 63,137 September 1997 962,446 249,487 191,800 December 1997 753,808 128,511 63,195 =================================================================
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 1998 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 generally accepted accounting principles appropriate in the circumstances, 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 books and 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 directors who are not employees, 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 generally accepted accounting principles.
/s/ H. Allen Franklin H. Allen Franklin President and Chief Executive Officer
/s/ David M. Ratcliffe David M. Ratcliffe Executive Vice President, Treasurer and Chief Financial Officer
February 10, 1999
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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, 1998 and 1997, and the related statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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-97 through II-117) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Arthur Andersen LLP
Atlanta, Georgia February 10, 1999
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1998 earnings totaled $570 million, representing a $24 million (4.0 percent) decrease from 1997. This earnings decrease resulted primarily from higher operating expenses, additional depreciation charges pursuant to a Georgia Public Service Commission (GPSC) retail accounting order discussed below, lower wholesale capacity revenues, and the write-off of a portion of the Rocky Mountain plant investment. These decreases to earnings were partially offset by higher retail revenues, lower financing costs and increased non-operating income. Earnings for 1997 totaled $594 million, representing a $14 million (2.4 percent) increase over 1996. This earnings increase resulted primarily from lower operating expenses, lower financing costs, and increased non-operating income, partially offset by lower retail revenues and additional depreciation charges pursuant to the GPSC retail accounting order.
Revenues
The following table summarizes the factors impacting operating revenues for the 1996-1998 period:
Increase (Decrease) From Prior Year ------------------------------------ 1998 1997 1996 ------------------------------------ Retail - (in millions) Sales growth $ 174 $ 62 $ 58 Weather 101 (74) (25) Fuel cost recovery 70 (30) 28 Demand-side programs (25) (3) (10) - - - - - - - -------------------------------------------------------------------- Total retail 320 (45) 51 - - - - - - - -------------------------------------------------------------------- Sales for resale - Non-affiliates (23) 1 (9) Affiliates 43 3 (41) - - - - - - - -------------------------------------------------------------------- Total sales for resale 20 4 (50) - - - - - - - -------------------------------------------------------------------- Other operating revenues 13 10 10 - - - - - - - -------------------------------------------------------------------- Total operating revenues $ 353 $ (31) $ 11 ==================================================================== Percent change 8.0% (0.7)% 0.3% - - - - - - - --------------------------------------------------------------------
Retail revenues of $4.3 billion in 1998 increased $320 million (8.0 percent) from 1997 primarily due to higher energy sales to residential and commercial customers. Retail revenues of $4.0 billion in 1997 decreased $45 million (1.1 percent) from 1996 primarily due to milder-than-normal weather, as well as commercial and industrial customers taking advantage of load management rates.
Fuel revenues generally represent the direct recovery of fuel expense, including the fuel component of purchased energy, and do not affect net income. Revenues from demand-side option programs generally represent the direct recovery of program costs. See Note 3 to the financial statements under "Demand-Side Conservation Programs" for further information on these programs.
Wholesale revenues from sales to non-affiliated utilities decreased slightly in 1998 and were as follows:
1998 1997 1996 ------------------------------- (in millions) Outside service area - Long-term contracts $ 51 $ 71 $ 84 Other sales 94 80 37 Inside service area 115 132 161 - - - - - - - --------------------------------------------------------------- Total $260 $283 $282 ===============================================================
Revenues from long-term contracts outside the service area decreased in 1998 primarily due to lower capacity charges and decreased energy sales and in 1997 primarily due to scheduled reductions in the amount of megawatt-hour capacity under these contracts. See Note 7 to the financial statements for further information regarding these sales. Revenues from other sales outside the service area increased in 1998 and 1997 primarily due to power marketing activities. These increases were primarily offset by increases in purchased power from non-affiliates and, as a result, had no significant effect on net income. Wholesale revenues from customers within the service area decreased in 1998 and 1997 primarily due to a decrease in revenues under a power supply agreement with Oglethorpe Power Corporation (OPC). OPC decreased its purchases of capacity by 250 megawatts each in September 1996, 1997, and 1998 and has notified the Company of its intent to decrease purchases of capacity by an additional 250 megawatts in September 1999 and 125 megawatts in September 2000.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
Kilowatt-hour (KWH) sales for 1998 and the percent change by year were as follows:
Percent Change ---------------------------- KWH 1998 1997 1996 ----------------------------------------- (in billions) Residential 19.5 12.6% (3.0)% 3.0% Commercial 22.9 8.2 1.5 4.9 Industrial 27.3 2.2 1.9 3.6 Other 0.5 1.0 0.4 8.6 -------- Total retail 70.2 6.9 0.4 3.9 -------- Sales for resale - Non-affiliates 6.4 (5.2) (13.6) 19.4 Affiliates 2.0 19.4 44.6 (56.9) -------- Total sales for resale 8.4 (0.3) (6.0) (3.0) -------- Total sales 78.6 6.0 (0.3) 3.0 ======== - - - - - - - ------------------------------------------------------------------
Residential and commercial sales increased in 1998 12.6 percent and 8.2 percent, respectively, and industrial sales increased slightly by 2.2 percent. The increases are attributed primarily to sales growth and hotter temperatures in the summer months. Residential sales in 1997 declined 3.0 percent while sales to commercial and industrial customers increased slightly by 1.5 percent and 1.9 percent, respectively. Milder-than-normal temperatures experienced in 1997 contributed to the moderate sales.
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:
1998 1997 1996 ------------------------- Total generation (billions of KWH) 69.1 66.5 63.7 Sources of generation (percent) -- Coal 73.3 74.8 74.3 Nuclear 21.6 21.8 22.4 Hydro 2.6 2.7 2.7 Oil and gas 2.5 0.7 0.6 Average cost of fuel per net KWH generated (cents) -- 1.36 1.32 1.35 - - - - - - - ---------------------------------------------------------------
Fuel expense increased 7.0 percent in 1998 primarily due to an increase in generation to meet higher energy demands and a higher average cost of fuel. Fuel expense increased 2.6 percent in 1997 primarily due to an increase in generation, partially offset by a lower average cost of fuel.
Purchased power expense increased $70 million (21.9 percent) to meet higher energy demands and power marketing activities. The majority of the energy purchased for power marketing activities was resold to non-affiliated third parties and had no significant effect on net income. In June 1998, the Company began purchasing capacity and energy from a 300 megawatt cogeneration facility pursuant to a 30-year purchase power agreement. Purchased power expense decreased $66 million (17.1 percent) in 1997 primarily due to decreased purchases from affiliated companies and declines in contractual capacity buyback purchases from the co-owners of Plant Vogtle. Under the terms of the 1991 retail rate order, the costs of declining Plant Vogtle contractual capacity buyback purchases were levelized over a six-year period ending September 1997. The levelization is reflected in the amortization of deferred Plant Vogtle costs in the Statements of Income. See Note 1 to the financial statements under "Plant Vogtle Phase-In Plans" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
Other operation and maintenance (O&M) expenses, excluding the provision for separation benefits, increased 15.9 percent primarily due to continuing expenses related to a new customer service system implemented in January 1998, modification of certain information systems for year 2000 compliance discussed below, an increase in outage costs at steam power generating facilities, and increased line maintenance. Other O&M expenses, excluding the provision for separation benefits, decreased 4.1 percent in 1997 primarily due to initiatives in 1996 to reduce fossil generation materials inventory levels and an adjustment in 1996 to deferred postretirement benefits to reflect changes in the retiree benefits plan.
Depreciation and amortization increased $191 million in 1998 and $140 million in 1997 primarily due to accelerated depreciation of generating plant pursuant to the retail accounting order and an increase in plant-in-service. See Note 3 to the financial statements under "Retail Rate Order" for additional information.
The Company has deferred certain expenses and recorded a deferred return related to Plant Vogtle under phase-in plans. The amortization of deferred Plant Vogtle costs reflects the completion in September 1997 of the amortization of the levelized buybacks and the Plant Vogtle Unit 1 cost deferrals under a 1987 GPSC order. In December 1998, the remaining Vogtle Unit 2 cost deferrals were fully amortized to expense under a 1998 retail rate order. See Note 1 to the financial statements under "Plant Vogtle Phase-In Plans" for information regarding the deferral and subsequent amortization of costs related to Plant Vogtle.
Additionally, as a result of the 1998 retail rate order, the Company recorded a $34 million pre-tax write-off associated with a portion of its investment in the Rocky Mountain plant. See Note 3 to the financial statements under "Rocky Mountain Plant Status" for additional information.
Other income (expense) increased in 1998 primarily due to the recognition of $73 million in interest income resulting from the resolution of tax issues with the Internal Revenue Service (IRS) and the State of Georgia. Other income (expense) increased in 1997 primarily due to increased tax benefits from losses of the parent company allocated to the Company under the joint consolidated income tax agreement between Southern Company and its subsidiaries. See Note 8 to the financial statements for additional information.
Total financing costs decreased in 1998 and 1997. These changes were primarily due to the refinancing or retirement of securities. The Company refinanced or retired $754 million and $701 million of securities in 1998 and 1997, respectively. Dividends on preferred stock decreased $13 million and $26 million in 1998 and 1997, respectively. These decreases were partially offset by increases in interest and other charges of $6 million and $17 million in 1998 and 1997, respectively, primarily due to the issuance of additional mandatorily redeemable preferred securities in 1996 and 1997.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
On January 1, 1999, the Company began operating under a new three-year retail rate order approved by the GPSC on December 18, 1998. The Company's earnings will continue to be evaluated against a retail return on common equity range of 10 percent to 12.5 percent, with rate reductions of $262 million in 1999 and an additional reduction of $24 million in 2000. The order provides for $85 million in each year, plus up to $50 million of any earnings in excess of 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 in excess of the 12.5 percent return will be applied to rate reductions, with the remaining one-third retained by the Company. The Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent, and will be required to file a general rate case on July 1, 2001 in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued. See Note 3 to the financial statements under "Retail Rate Order" for additional information.
Under a previous three-year accounting order ending December 1998, the Company's earnings were evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Earnings in excess of 12.5 percent were used to accelerate the amortization of regulatory assets or depreciation of electric plant.
As a result of the Company recognizing the write-off of a portion of its cost in the Rocky Mountain plant and completing the amortization of deferred Plant Vogtle costs in 1998 in accordance with the new retail rate order, future depreciation and amortization will decrease. Future depreciation and amortization will also decrease as a result of the cap on the amount of accelerated amortization or depreciation of assets under the new retail rate order. 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 is projected to be approximately 2 percent annually on average during 1999 through 2001.
In September 1998, OPC decreased its purchases of capacity under a power supply agreement by 250 megawatts and has notified the Company of its intent to decrease purchases of capacity by an additional 250 megawatts in September 1999 and 125 megawatts in September 2000. As a result, the Company's capacity revenues from OPC will decline by approximately $23 million in 1999, an additional $19 million in 2000, and an additional $4 million in 2001. Under the amended 1995 Integrated Resource Plan approved by the GPSC in March 1997, the resources associated with the decreased purchases in 1998 will be used to meet the needs of the Company's retail customers through 2004. See Note 3 to the financial statements under "FERC Review of Equity Returns" for additional information about other wholesale regulatory matters.
The Company has entered into a five-year purchase power agreement scheduled to begin in June 2000 for approximately 215 megawatts. Capacity and fixed O&M payments are estimated to be between $7 million and $8 million each year.
The Company plans to construct an eight unit, 600-megawatt combustion turbine peaking power plant that will begin operation in 2000 and will serve the wholesale market. The plant will supply power to fulfill a contract for 400 megawatts of peaking power already established with the Company. The addition of this facility will increase related O&M and depreciation expenses for the Company. Because the plant will be dedicated to the wholesale market, retail rates will not be affected. The Company may expand the facility to a total of 1,200 to 1,900 megawatts of capacity over the next two to three years in order to meet additional anticipated wholesale power demand.
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 further under "Environmental Issues."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
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 electric energy 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. 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.
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 plans to release a schedule and procedure order for a stranded costs docket in the first half of 1999. The ability 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 and other costs through the three-year retail rate order. See Note 3 to the financial statements under "Retail Rate Order" for additional information.
Unless the Company remains a low-cost producer and provides quality service, the Company's retail energy sales growth could be limited as competition increases. Conversely, continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation.
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry - including the Company's - regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating facilities in the financial statements. In response to these questions, the FASB has decided to review 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s shortened the year portion of date entries to just two digits. Computers assumed, in effect, that all years began with "19." This practice was widely adopted and hard-coded into computer chips and processors found in some equipment. This approach, intended to save processing time and storage space, was used until the mid-1990s. Unless corrected before the year 2000, affected software systems and devices containing a chip or microprocessor with date and time functions could incorrectly process dates or the systems may cease to function.
The Company depends on complex computer systems for many aspects of its operations, which include generation, transmission, and distribution of electricity, as well as other business support activities. The Company's goal is to have critical devices or software that are required to maintain operations to be Year 2000 ready by June 1999. Year 2000 ready means that a system or application is determined suitable for continued use through the Year 2000 and beyond. Critical systems include, but are not limited to, reactor control systems, safe shutdown systems, turbine generator systems, control center computer systems, customer service systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000 challenge and has dedicated what it believes to be adequate resources to address the issue. The Millennium Project is a team of employees, IBM consultants, and other contractors whose progress is reviewed on a monthly basis by a steering committee of Southern Company executives.
The Company's Year 2000 program was divided into two phases. Phase I began in 1996 and consisted of identifying and assessing corporate assets related to software systems and devices that contain a computer chip or clock. The first phase was completed in June 1997. Phase 2 consists of testing and remediating high priority systems and devices. Also, contingency planning is included in this phase. Completion of Phase 2 is targeted for June 1999. The Millennium Project will continue to monitor the affected computer systems, devices, and applications into the year 2000.
The Southern Company has completed more than 70 percent of the activities contained in its work plan. The percentage of completion and projected completion by function are as follows:
- - - - - - - ------------------------------------------------------------------------------ Work Plan ---------------------------------------------------- Remediation Project Inventory Assessment Testing Completion - - - - - - - ----------------------------------------------------------------------------- Generation 100% 100% 70% 6/99 - - - - - - - ----------------------------------------------------------------------------- Energy Management 100 100 90 6/99 - - - - - - - ----------------------------------------------------------------------------- Transmission and Distribution 100 100 100 1/99 - - - - - - - ----------------------------------------------------------------------------- Telecommunications 100 100 50 6/99 - - - - - - - ----------------------------------------------------------------------------- Corporate Applications 100 100 90 3/99 - - - - - - - -----------------------------------------------------------------------------
Year 2000 Costs
Current projected total costs for Year 2000 readiness, including the Company's share of costs of Southern Nuclear Operating Company, are approximately $38 million. These costs include labor necessary to identify, test, and renovate affected devices and systems. From its inception through December 31, 1998, the Year 2000 program costs, recognized as expense, amounted to $27 million.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of service interruptions related to the Year 2000. The Company believes, based on current tests, that the system can provide customers with electricity. These tests increase confidence, but do not guarantee error-free operation. The Company is taking what it believes to be prudent steps to prepare for the Year 2000, and it expects any interruptions in service that may occur within the service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe than the scenarios that its electric system is routinely prepared to handle. The most likely worst case scenario consists of the service loss of one of the largest generating units and/or the service loss of any single bulk transmission element in its service territory. The Company has followed a proven methodology
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
for identifying and assessing software and devices containing potential Year 2000 challenges. Remediation and testing of those devices are in progress. Following risk assessment, the Company is preparing contingency plans as appropriate and is participating in North American Electric Reliability Council - - - - - - - - coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third parties that provide goods and services crucial to the Company's operations. Among such critical third parties are fuel, transportation, telecommunications, water, chemical, and other suppliers. Contingency plans based on the assessment of each third party's ability to continue supplying critical goods and services to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical demand by customers because of their Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled at developing and using contingency plans in unusual circumstances. As part of Year 2000 business continuity and contingency planning, the Company is drawing on that experience to make risk assessments and is developing additional plans to deal specifically with situations that could arise relative to Year 2000 challenges. The Company is identifying critical operational locations, and key employees will be on duty at those locations during the Year 2000 transition. In September 1999, drills are scheduled to be conducted to test contingency plans. Because of the level of detail of the contingency planning process, management feels that the contingency plans will keep any service interruptions that may occur within the service territory isolated and short in duration.
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 statement as incurred. At December 31, 1998, 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, 1998, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by the year 2000. This statement establishes accounting and reporting standards for derivative instruments - including certain derivative instruments embedded in other contracts - and for hedging activities. The Company has not yet quantified the impact of adopting this statement on its financial statements; however, the adoption could increase volatility in earnings.
In March 1998, the American Institute of Certified Public Accountants (AICPA) issued a new Statement of Position, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement requires capitalization of certain costs of internal-use software. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the Costs of Start-up Activities. This statement requires that the costs of start-up activities and organizational costs be expensed as incurred. Any of these costs previously capitalized by a company must be written off in the year of adoption. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The EITF requires that energy trading contracts must be marked to market through the income statement, with gains and losses reflected rather than revenues and purchased power. Energy trading contracts are defined
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
as energy contracts entered into with the objective of generating profits on or from exposure to shifts or changes in market prices. The Company adopted the required accounting in January 1999, and it is not expected to have a material impact on the financial statements.
FINANCIAL CONDITION
Plant Additions
In 1998 gross utility plant additions were $499 million. These additions were primarily related to transmission and distribution facilities and to the purchase of nuclear fuel. The funds needed for gross property additions are currently provided from operations. The Statements of Cash Flows provide additional details.
Financing Activities
In 1998 the Company continued to lower its financing costs by refinancing higher-cost issues. New issues during 1996 through 1998 totaled $1.6 billion and retirement or repayment of securities totaled $2.0 billion. Composite financing rates for long-term debt and preferred stock for the years 1996 through 1998, as of year-end, were as follows:
1998 1997 1996 ---------------------------------- Composite interest rate on long-term debt 5.64% 6.11% 6.39% Composite preferred stock dividend rate 5.52 5.18 6.34 - - - - - - - ------------------------------------------------------------------
Subsidiaries of the Company have issued mandatorily redeemable preferred securities. See Note 9 to the financial statements under "Preferred Securities" for additional information.
Liquidity and Capital Requirements
Cash provided from operations increased by $30 million in 1998, primarily due to higher retail revenues.
The Company estimates that construction expenditures for the years 1999 through 2001 will total $755 million, $734 million and $829 million, 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 improvement fund requirements, redemptions announced, and maturities of long-term debt and preferred stock are expected to total $601 million during 1999 through 2001.
As a result of requirements by the Nuclear Regulatory Commission, the Company has established external trust funds for the purpose of funding nuclear decommissioning costs. The amount to be funded is $24 million in 1999 and increases to $30 million in 2000 and 2001. 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, 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 $1.3 billion of unused credit arrangements with banks at the beginning of 1999. See Note 9 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. In this regard, the Company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur.
If the Company chooses to issue first mortgage bonds or preferred stock, it 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
Environmental Issues
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly impacted the operating companies of Southern Company, including Georgia Power. 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 initially affected 28 generating units in the Southern electric system. As a result of Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants in the Southern electric system will be affected.
Southern 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 Georgia Power's Phase I compliance totaled approximately $167 million.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Georgia Power's current compliance strategy for Phase II and ozone non-attainment could require total estimated construction expenditures of approximately $39 million, of which $14 million remains to be spent as of December 31, 1998.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. In September 1998, the EPA issued the final regional nitrogen oxide rules to the states for implementation. The states have one year to adopt and implement the new rules. The final rules affect 22 states including Georgia. The EPA rules are being challenged in the courts by several states and industry groups. Implementation of the final state rules could require substantial further reductions in nitrogen oxide emissions from fossil-fired generating facilities and other industry in these states. Implementation of the standards could result in significant additional compliance costs and capital expenditures that cannot be determined until the results of legal challenges are known and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: nitrogen oxide emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; control strategies to reduce regional haze; and hazardous waste disposal requirements. The impact of 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. 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 $6 million, $4 million and $2 million, in 1998, 1997 and 1996, 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 "Certain 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.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1998 Annual Report
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 1998 Annual Report contains forward-looking and historical information. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking information; accordingly, there can be no assurance that such indicated results will be realized. These factors include legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry; 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 internal restructuring -- that may be pursued by Southern Company; state and federal rate regulation; Year 2000 issues; changes in or application of environmental and other laws and regulations to which the Company is subject; political, legal and economic conditions and developments; financial market conditions and the results of financing efforts; changes in commodity prices and interest rates; weather and other natural phenomena; and other factors discussed in the reports--including Form 10-K--filed from time to time by the Company with the Securities and Exchange Commission.
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STATEMENTS OF INCOME For the Years Ended December 31, 1998, 1997, and 1996 Georgia Power Company 1998 Annual Report
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BALANCE SHEETS At December 31, 1998 and 1997 Georgia Power Company 1998 Annual Report
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BALANCE SHEETS (continued) At December 31, 1998 and 1997 Georgia Power Company 1998 Annual Report
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NOTES TO FINANCIAL STATEMENTS Georgia Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, Southern Company Services (SCS), a system service company, Southern Communications Services (Southern LINC), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The operating companies (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four Southeastern states. Contracts among the operating companies -- dealing with 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 operating companies and also markets these services to the public within the Southeast. Southern Energy designs, builds, owns, and operates power production and delivery facilities and provides a broad range of energy related services in the United States and international markets. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Company Energy Solutions develops new business opportunities related to energy products and services.
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 this act. The Company is also subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). The Company follows generally accepted accounting principles (GAAP) and complies with the accounting policies and practices prescribed by the respective regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from these estimates.
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 Company's Balance Sheets at December 31 relate to the following:
1998 1997 ---------------------- (in millions) Deferred income taxes $ 604 $ 688 Deferred income tax credits (284) (298) Premium on reacquired debt 174 167 Corporate building lease 53 52 Deferred Plant Vogtle costs - 50 Vacation pay 44 41 Postretirement benefits 36 38 Department of Energy assessments 26 29 Deferred nuclear outage costs 24 28 Demand-side program costs - 11 Other, net 12 10 - - - - - - - --------------------------------------------------------------- Total $ 689 $ 816 ===============================================================
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 net 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) Georgia Power Company 1998 Annual Report
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 by type of service were as follows:
1998 1997 1996 -------------------------------- (in millions) Retail $4,298 $3,978 $4,023 Non-affiliated wholesale 260 283 282 Other 99 86 76 - - - - - - - --------------------------------------------------------------- Total $4,657 $4,347 $4,381 ===============================================================
The Company accrues revenues for service rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The Company's electric rates include provisions to adjust billings for fluctuations in fuel costs, 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 $74 million in 1998, $76 million in 1997, and $78 million in 1996. 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. Sufficient storage capacity currently is available to permit operation into 2003 at Plant Hatch and into 2017 at Plant Vogtle. Plant Vogtle's spent fuel storage capacity includes the installation in 1998 of additional rack capacity. Activities for adding dry cask storage capacity at Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a Uranium Enrichment Decontamination and Decommissioning Fund, which is to be funded in part by a special assessment on utilities with nuclear plants. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The assessment will be paid over a 15-year period, which began in 1993. 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, 1998, to be approximately $24 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 3.2 percent in 1998 and 3.1 percent in 1997 and 1996. In addition, the Company recorded accelerated depreciation of electric plant of $316 million in 1998, $159 million in 1997, and $24 million in 1996. The amount of such charges in the accumulated provision for depreciation is $505 million at December 31, 1998. See Note 3 under "Retail Rate Order" for additional information. 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 costs of decommissioning nuclear facilities and removal of other facilities.
Nuclear Regulatory Commission (NRC) regulations require 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 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.
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NOTES (continued) Georgia Power Company 1998 Annual Report
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 3.6% for the Company's ownership interests are as follows: Plant Plant Hatch Vogtle -------------------- Site study basis (year) 1997 1997
Decommissioning periods: Beginning year 2014 2027 Completion year 2027 2038 - - - - - - - ------------------------------------------------------------- (in millions) Site study costs: Radiated structures $372 $317 Non-radiated structures 33 44 - - - - - - - ------------------------------------------------------------- Total $405 $361 ============================================================= (in millions) Ultimate costs: Radiated structures $722 $ 922 Non-radiated structures 65 129 - - - - - - - ------------------------------------------------------------- Total $787 $1,051 =============================================================
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, changes in the assumptions used in making estimates, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials, and equipment.
Annual provisions for nuclear decommissioning expense are based on an annuity method as approved by the GPSC. The amounts expensed in 1998 and fund balance as of December 31, 1998 were: Plant Plant Hatch Vogtle - - - - - - - ------------------------------------------------------------- (in millions) Amount expensed in 1998 $ 11 $ 9 - - - - - - - -------------------------------------------------------------
Accumulated provisions: Balance in external trust funds $172 $112 Balance in internal reserves 19 12 - - - - - - - ------------------------------------------------------------- Total $191 $124 =============================================================
Effective January 1, 1999, the GPSC increased the annual provision for decommissioning expenses to $26 million. This amount is based on the NRC generic estimate to decommission the radioactive 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% and an estimated trust earnings rate of 6.5%. 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.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle, a two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased into rates. Pursuant to the orders, the Company recorded a deferred return under phase-in plans until October 1991 when the allowed investment was fully reflected in rates. In 1991, the GPSC levelized the remaining Plant Vogtle declining capacity buyback expenses over a six-year period. In addition, the Company deferred certain Plant Vogtle operating expenses and financing costs under accounting orders issued by the GPSC. These GPSC orders provided for the recovery of deferred costs within 10 years. Costs deferred under the 1987 order and the levelized buybacks were fully recovered as of September 1997. Under a December 18, 1998 retail rate order from the GPSC, the remaining deferred costs were fully amortized to expense in December 1998. See Note 3 under "Retail Rate Order" for additional information.
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
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NOTES (continued) Georgia Power Company 1998 Annual Report
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 1998, 1997 and 1996, the average AFUDC rates were 6.71 percent, 7.60 percent and 6.59 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 2.0 percent for 1998, 1997, and 1996.
Utility Plant
Utility plant is stated at original cost, less regulatory disallowances. 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 charged to utility plant.
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'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, 1998 $3,058 $3,105 At December 31, 1997 3,125 3,170 Preferred securities: At December 31, 1998 689 716 At December 31, 1997 689 720 - - - - - - - --------------------------------------------------------------
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 trusts to the extent deductible under federal income tax regulations or to the extent required by the GPSC and FERC. In 1998, the Company adopted FASB Statement No. 132, Employers' Disclosure about Pensions and Other Postretirement Benefits. The measurement date is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were:
1998 1997 - - - - - - - ----------------------------------------------------------------- Discount 6.75% 7.50% Annual salary increase 4.25 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 --------------------------- 1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Balance at beginning of year $1,119 $1,172 Service cost 30 30 Interest cost 82 82 Benefits paid (55) (42) Actuarial (gain) loss and employee transfers 41 (123) - - - - - - - ---------------------------------------------------------------- Balance at end of year $1,217 $1,119 ================================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Balance at beginning of year $1,931 $1,797 Actual return on plan assets 11 338 Benefits paid (55) (42) Employee transfers (28) (162) - - - - - - - ---------------------------------------------------------------- Balance at end of year $1,859 $1,931 ================================================================
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NOTES (continued) Georgia Power Company 1998 Annual Report
The accrued pension costs recognized in the Balance Sheets were as follows: 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Funded status $ 642 $ 812 Unrecognized transition obligation (35) (39) Unrecognized prior service cost 45 48 Unrecognized net actuarial gain (548) (753) - - - - - - - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 104 $ 68 ===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - --------------------------------------------------------------- (in millions) Service cost $ 30 $ 30 $ 35 Interest cost 82 82 86 Expected return on plan assets (127) (121) (124) Recognized net actuarial gain (20) (18) (14) Net amortization (1) (1) (2) - - - - - - - --------------------------------------------------------------- Net pension income $ (36) $ (28) $ (19) ===============================================================
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Balance at beginning of year $ 435 $ 430 Service cost 7 7 Interest cost 32 32 Benefits paid (16) (13) Actuarial loss and employee transfers 6 (21) - - - - - - - ---------------------------------------------------------------- Balance at end of year $ 464 $ 435 ================================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - ---------------------------------------------------------------- (in millions) Balance at beginning of year $122 $112 Actual return on plan assets 4 9 Employer contributions 40 14 Benefits paid (16) (13) - - - - - - - ---------------------------------------------------------------- Balance at end of year $150 $122 ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows: 1998 1997 - - - - - - - --------------------------------------------------------------- (in millions) Funded status $ (314) $ (313) Unrecognized transition obligation 131 139 Unrecognized net actuarial loss 57 47 Fourth quarter contributions 19 29 - - - - - - - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (107) $ (98) ===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - --------------------------------------------------------------- (in millions) Service cost $ 7 $ 7 $ 9 Interest cost 32 32 30 Expected return on plan assets (9) (7) (5) Recognized net actuarial loss 1 1 2 Net amortization 9 9 9 - - - - - - - --------------------------------------------------------------- Net postretirement cost $ 40 $ 42 $ 45 ===============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.30 percent for 1998, decreasing gradually to 4.75 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, 1998 as follows:
1 Percent 1 Percent Increase Decrease - - - - - - - --------------------------------------------------------------- (in millions) Benefit obligation $ 38 $ (32) Service and interest costs 3 (3) ===============================================================
3. REGULATORY AND LITIGATION MATTERS
Retail Rate Order
As required by the GPSC, the Company filed a general rate case in 1998. On December 18, 1998, the GPSC approved a new three-year rate order for the Company. Under terms of the order, earnings will continue to be evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Retail rates will be decreased by $262 million on an annual basis effective January 1, 1999, and by an additional $24 million effective January 1, 2000. The
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order further provides for $85 million in each year, plus up to $50 million of any earnings in excess of 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 in excess of the 12.5 percent return will be applied to rate reductions, with the remaining one-third retained by the Company. The Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent, and will be required to file a general rate case on July 1, 2001, in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued.
Under a previous three-year accounting order ending December 1998, the Company's earnings were evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Earnings in excess of 12.5 percent were used to accelerate the amortization of regulatory assets or depreciation of electric plant. The Company was required to absorb cost increases of approximately $29 million annually during the order's three-year operation, including $14 million annually of accelerated depreciation of electric plant.
The Company's 1996 retail return on common equity was within the 10 percent to 12.5 percent range. During 1998 and 1997, for earnings in excess of the 12.5 percent retail return, the Company recorded charges of $292 million and $135 million, respectively, that are presented in the financial statements as depreciation expense of electric plant and as an addition to the accumulated provision for depreciation.
FERC Review of Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of the administrative law judge's opinions in two proceedings in which the return on common equity component of formula rates contained in substantially all of the operating companies' wholesale power contracts was being challenged as unreasonably high. These orders resulted in no change in the wholesale power contracts that were the subject of such proceedings. The FERC also dismissed a complaint filed by three customers under long-term power sales agreements seeking to lower the equity return component in such agreements. These customers have filed applications for rehearing regarding each FERC order. In response to a requirement of the September 1998 FERC order, Southern Company filed a new equity return component on the long-term power sales contracts, to be effective January 5, 1999. The proposed equity return was lowered from 13.75 percent to 12.50 percent. If the filed return is approved, annual revenues will decrease by approximately $1 million. The FERC placed the new rates into effect, subject to refund. Also, this filing was consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to initiate a new proceeding regarding the equity return and other issues involving the Company's formula rate contracts. The motion was submitted pursuant to review procedures applicable to theses contracts, and would be applicable to billings under such contracts on and after January 1, 1999.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky Mountain pumped storage hydroelectric plant in 1991, as then planned, was not economically justifiable and reasonable and withheld authorization for the Company to spend funds from approved securities issuances on that plant. In 1988, the Company and Oglethorpe Power Corporation (OPC) entered into a joint ownership agreement for OPC to assume responsibility for the construction and operation of the plant, as discussed in Note 6. In 1995, the plant went into commercial operation.
In June 1996, the GPSC initiated a review of the plant. On January 14, 1998, the GPSC ordered that the Company be allowed approximately $108 million of its $142 million investment in the plant in rate base as of December 31, 1998. The Company appealed the GPSC's order to the Superior Court of Fulton County, Georgia. Under the rate order approved by the GPSC on December 18, 1998, the Company voluntarily dismissed the appeal. As a result, in December 1998, the Company recorded a charge to earnings of $21 million, after taxes, associated with the write-down of the plant.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered into a settlement agreement related to tax issues for the years 1984 through 1987. The agreement received final approval by the Joint Congressional Committee on Taxation in June 1998 and as a result, the Company recognized interest income in 1998 of $69 million. The refund by the IRS has been made and this matter is now concluded.
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Additionally, the Company received a refund from the State of Georgia pertaining to the same issues and recognized an additional $4 million in interest income in 1998.
Demand-Side Conservation Programs
In August 1995, the GPSC ordered the Company to discontinue its current demand-side conservation programs by the end of 1995. Rate riders previously approved by the GPSC for recovery of the Company's costs incurred in connection with these programs remained in effect until January 1998 when costs deferred were fully collected.
Under a GPSC accounting order approved February 16, 1996, the Company recognized approximately $29 million of deferred program costs over a three-year period ending December 1998, which were not recovered through the riders.
Certain 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, 1998, the Company has recognized approximately $5 million in cumulative expenses associated with this site. This represents the Company's agreed upon share of removal and remedial investigation and feasibility study costs. 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.
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 26 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 nine electrical substations on the list at a cumulative cost of approximately $3 million. The State has removed from the list one power generation facility following the assessment which indicated no remediation was necessary. In addition, the Company has recognized approximately $23 million in cumulative expenses through December 31, 1998 for the assessment of the remaining sites on the list and the anticipated clean-up cost for 11 sites that the Company plans to remediate. Any cost of remediating the remaining sites cannot presently be determined until such studies are completed for each site and the State of Georgia determines whether remediation is required. If all listed sites were required to be remediated, the Company could incur expenses of up to approximately $10 million in additional clean-up costs and construction expenditures of up to approximately $56 million to develop new waste management facilities or install additional pollution control devices.
The accrued costs for environmental remediation obligations are not discounted to their present value.
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 will be evaluated every three years. The performance standard is based on each unit's capacity factor as compared to the average of all comparable U.S. nuclear units operating at a capacity factor of 50 percent or higher during the three-year period of evaluation. Depending on the performance of the units, the Company could receive a monetary award or penalty under the performance standards criteria.
The first evaluation was conducted in 1993 for performance during the 1990-92 period. The GPSC approved a performance award of approximately $8.5 million for the Company. This award was collected through the retail fuel cost recovery provision and recognized in income over a 36-month period which ended in October 1996. In January 1997, the GPSC approved a performance award of approximately $11.7 million for performance during the 1993-95 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 1997.
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4. COMMITMENTS
Construction Program
While the Company has no traditional baseload generating plants under construction, the construction of eight combustion turbine peaking units is planned to be completed by 2000. In addition, 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 $755 million in 1999, $734 million in 2000, and $829 million in 2001.
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, 1998 were as follows: Minimum Year Obligations ---------------------- (in millions) 1999 $ 642 2000 545 2001 483 2002 414 2003 366 2004 and beyond 719 - - - - - - - ---------------------------------------------------------------- Total minimum obligations $3,169 ================================================================
Additional commitments for coal and for nuclear fuel will be required in the future to supply the Company's fuel needs.
Purchased Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed in Note 6, the Company has made commitments to purchase portions of OPC's and the Municipal Electric Authority of Georgia's (MEAG's) capacity and energy from this plant. Declining commitments were in effect during periods of up to seven years following commercial operation and ended in 1996. In addition, the Company has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. 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 $56 million, $54 million, and $68 million in 1998, 1997, and 1996, respectively. The current projected Plant Vogtle capacity payments are:
Year Amounts ---------------------- (in millions) 1999 $ 59 2000 62 2001 61 2002 60 2003 60 2004 and beyond 711 - - - - - - - ---------------------------------------------------------------- Total $ 1,013 ================================================================
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 and an affiliate, Alabama 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, 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
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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:
1998 1997 1996 --------------------------------- (in millions) Energy $45 $45 $47 Capacity 30 30 30 - - - - - - - -------------------------------------------------------------- Total $75 $75 $77 ============================================================== Kilowatt-hours 3,146 3,038 2,780 - - - - - - - --------------------------------------------------------------
At December 31, 1998, the capitalization of SEGCO consisted of $49 million of equity and $70 million of long-term debt on which the annual interest requirement is $4 million.
The Company has entered into other various long-term commitments for the purchase of electricity. Total long-term obligations at December 31, 1998 were as follows:
Year Amounts ---------------------- (in millions) 1999 $ 18 2000 21 2001 22 2002 23 2003 23 2004 and beyond 363 - - - - - - - ---------------------------------------------------------------- Total $ 470 ================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $13 million for 1998, and $11 million each for 1997 and 1996. At December 31, 1998, estimated minimum rental commitments for these noncancelable operating leases were as follows:
Year Amounts ---------------------- (in millions) 1999 $ 11 2000 11 2001 11 2002 12 2003 12 2004 and beyond 120 - - - - - - - ---------------------------------------------------------------- Total $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 $9.7 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. 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 17 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 $25 million.
For all on-site property damage insurance policies for commercial nuclear
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power plants, the NRC requires that the proceeds of such policies issued or renewed on or after April 2, 1991, 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.
6. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
The Company has sold undivided interests in plants Hatch, Wansley, Vogtle, and Scherer Units 1 and 2 to OPC, an electric membership generation and transmission corporation; MEAG, a public corporation and an instrumentality of the state of Georgia; and the City of Dalton, Georgia. The Company has sold an interest in Plant Scherer Unit 3 to Gulf Power Company, an affiliate. Additionally, the Company has sold 76.4 percent of Plant Scherer Unit 4 to Florida Power & Light Company (FP&L) and the remaining 23.6 percent to Jacksonville Electric Authority (JEA). The Company has also sold transmission facilities to Georgia Transmission Corporation (formerly OPC's transmission division), MEAG, and the City of Dalton.
Except as otherwise noted, the Company has contracted to operate and maintain all jointly owned facilities. The Company includes its proportionate share of plant operating expenses in the corresponding operating expenses in the Statements of Income.
The Company owns 25.4 percent of the Rocky Mountain pumped storage hydroelectric plant. OPC owns the remainder, and is the operator of the plant. The Company owns six of eight 80 megawatt combustion turbine generating units and 75 percent of the related common facilities at Plant McIntosh. Savannah Electric and Power Company, an affiliate, owns the remainder and operates the plant. The Company and Florida Power Corporation (FPC) jointly own a combustion turbine unit at Intercession City, Florida, near Orlando. The unit began commercial operation in January 1997, and is operated by FPC. The Company owns a one-third interest in the unit, with use of 100 percent of the unit's capacity from June through September. FPC has the capacity the remainder of the year.
At December 31, 1998, 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% $3,296* $1,514 Plant Hatch (nuclear) 50.1 840 538 Plant Wansley (coal) 53.5 298 141 Plant Scherer (coal) Units 1 and 2 8.4 112 48 Unit 3 75.0 545 179 Plant McIntosh Common Facilities 75.0 19 1 (combustion-turbine) Rocky Mountain 25.4 169* 61 (pumped storage) Intercession City 33.3 12 ** (combustion-turbine) - - - - - - - -------------------------------------------------------------------- * Investment net of write-offs. ** Less than $1 million.
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries 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 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) 1998 $ 32 162 1997 42 159 1996 41 173 -------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA, and the City of Tallahassee, Florida. Under these agreements, the Company sold approximately 162 megawatts of capacity in 1998 and is scheduled to sell approximately 162 megawatts of capacity in 1999. In 2000, 129 megawatts will be sold. After 2000, capacity sales will decline to approximately 105 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in 2010. II-113
NOTES (continued) Georgia Power Company 1998 Annual Report
8. INCOME TAXES
At December 31, 1998, tax-related regulatory assets were $604 million and tax-related regulatory liabilities were $284 million. The assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. 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:
1998 1997 1996 ------------------------------- Total provision for income taxes: (in millions) Federal: Currently payable $ 415 $352 $325 Deferred - Current year 131 49 70 Reversal of prior years (218) (68) (41) Deferred investment tax credits 7 - - - - - - - - - ----------------------------------------------------------------- 335 333 354 - - - - - - - ----------------------------------------------------------------- State: Currently payable 77 65 56 Deferred - Current year 18 8 12 Reversal of prior years (31) (11) (5) - - - - - - - ----------------------------------------------------------------- 64 62 63 - - - - - - - ----------------------------------------------------------------- Total 399 395 417 - - - - - - - ----------------------------------------------------------------- Less: Income taxes credited to other income (8) (32) (19) - - - - - - - ----------------------------------------------------------------- Total income taxes charged to operations $ 407 $427 $436 =================================================================
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:
1998 1997 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,670 $1,732 Property basis differences 854 968 Other 158 142 - - - - - - - ---------------------------------------------------------------- Total 2,682 2,842 - - - - - - - ---------------------------------------------------------------- Deferred tax assets: Other property basis differences 211 216 Federal effect of state deferred taxes 95 99 Other deferred costs 96 83 Disallowed Plant Vogtle buybacks 23 23 Other 21 14 - - - - - - - ---------------------------------------------------------------- Total 446 435 - - - - - - - ---------------------------------------------------------------- Net deferred tax liabilities 2,236 2,407 Portion included in current assets 13 11 - - - - - - - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $2,249 $2,418 ================================================================
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 $22 million in 1998, $15 million in 1997, and $17 million in 1996. At December 31, 1998, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
1998 1997 1996 -------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 6 4 3 Other (4) (4) (2) - - - - - - - --------------------------------------------------------------- Effective income tax rate 41% 39% 40% ===============================================================
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. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
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NOTES (continued) Georgia Power Company 1998 Annual Report
9. CAPITALIZATION
First Mortgage Bond Indenture & Charter Restrictions
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. In this regard, the Company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur.
The Company's first mortgage bond indenture contains various restrictions that remain in effect as long as the bonds are outstanding. At December 31, 1998, $883 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.
Preferred Securities
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole general partner, issued $100 million of 9 percent mandatorily redeemable preferred securities. Substantially all of the assets of Georgia Power Capital, L.P., are $103 million aggregate principal amount of Georgia Power's 9 percent Junior Subordinated Deferrable Interest Debentures due December 19, 2024.
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
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. In February 1999, the Company issued an additional $200 million of mandatorily redeemable preferred securities (Trust IV), bearing interest at 6.85 percent. The associated junior subordinated notes will be due March 31, 2029.
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 Georgia Power Capital, L.P.'s and the Trusts' payment obligations with respect to the preferred securities.
Georgia Power Capital, L.P., and 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 $1.2 billion of its first mortgage bonds, 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 January, November, and December 1998, the Company issued unsecured senior notes. 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 1999, the Company had unused credit arrangements with banks totaling $1.3 billion, of which $722 million expires at various times during 1999, $30 million expires at May 1, 2000, and $500 million expires at April 24, 2003.
Of the total $1.3 billion in unused credit, $1 billion is a syndicated credit arrangement with $500 million expiring April 23, 1999 and $500 million expiring April 24, 2003. Both agreements provide the option of converting borrowings into two-year term loans upon expiration date. The agreements contain stated borrowing rates but also allow for competitive bid loans. In addition, the agreements require payment of commitment fees based on the unused portions of the commitments. Annual fees are also paid to the agent bank.
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NOTES (continued) Georgia Power Company 1998 Annual Report
Approximately $162 million of the $722 million arrangements expiring during 1999 allow for two-year term loans executable upon expiration date of the credit facilities. The $30 million credit arrangement expiring at May 1, 2000 allows for term loans of up to three years. 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.
The $1.3 billion in unused credit arrangements provide liquidity support to the Company's variable rate pollution control bonds. The amount of variable rate pollution control bonds outstanding as of December 31, 1998 was $979 million.
In addition, the Company borrows under uncommitted lines of credit with banks and through a $225 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 1998.
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, 1998 and 1997, 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, 1998 and 1997, the interest and lease amortization deferred on the Balance Sheets are $53 million and $52 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:
1998 1997 ------------------- (in millions) Bond improvement fund requirements $ 9 $ 15 Less: Portion to be satisfied by certifying property additions - - - - - - - - - ---------------------------------------------------------------- Cash requirements 9 15 First mortgage bond maturities and redemptions 390 205 - - - - - - - ---------------------------------------------------------------- Total long-term debt 399 220 Preferred stock 36 - - - - - - - - ---------------------------------------------------------------- Total $435 $220 ================================================================
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. The 1999 requirement was met in the first quarter of the year by depositing cash with the trustee. These funds were used to redeem first mortgage bonds.
Redemption of Securities
The Company plans to continue a program of redeeming or replacing debt and preferred stock 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 1998 Annual Report
In general, for the first five years a series of first mortgage bonds is outstanding, the Company is prohibited from redeeming for improvement fund purposes more than 1 percent annually of the original issue amount.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1998 and 1997 is as follows:
Net Income After Dividends on Operating Operating Preferred Stock Quarter Ended Revenues Income - - - - - - - --------------------------------------------------------------------- (in millions) -------------------------------------------- March 1998 $ 984 $177 $ 106 June 1998 1,226 188 137 September 1998 1,530 325 255 December 1998 998 104 72
March 1997 $ 959 $180 $ 106 June 1997 1,015 205 131 September 1997 1,407 317 257 December 1997 1,005 159 100 - - - - - - - ---------------------------------------------------------------------
Earnings in the fourth quarter of 1998, compared to the fourth quarter of 1997, decreased primarily as a result of the December 1998 Rocky Mountain write-off.
The Company's business is influenced by seasonal weather conditions.
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GULF POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Gulf Power Company 1998 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 generally accepted accounting principles appropriate in the circumstances 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 books and 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 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 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 generally accepted accounting principles.
/s/ Travis J. Bowden /s/ Arlan E. Scarbrough Travis J. Bowden Arlan E. Scarbrough President Chief Financial Officer and Chief Executive Officer
February 10, 1999
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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, 1998 and 1997, and the related statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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-134 through II-150) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Atlanta, Georgia February 10, 1999 II-124
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1998 net income after dividends on preferred stock was $56.5 million, a decrease of $1.1 million from the previous year. The decrease in earnings was primarily a result of higher operating expenses in 1998 when compared to 1997.
In 1997, earnings were $57.6 million, down $0.2 million when compared to 1996. The change was attributed to lower residential revenues due to milder-than-normal weather.
Revenues
Operating revenues increased in 1998 when compared to 1997 and decreased in 1997 when compared to 1996. The following table summarizes the factors impacting operating revenues for the past three years:
Increase (Decrease) From Prior Year --------------------------------------- 1998 1997 1996 --------------------------------------- (in thousands) Retail -- Sales growth $15,021 $ 4,005 $ 7,123 Weather 6,656 (5,277) (1,057) Regulatory cost recovery and other (34,179) (7,837) 5,649 - - - - - - - -------------------------------------------------------------------- Total retail (12,502) (9,109) 11,715 - - - - - - - -------------------------------------------------------------------- Sales for resale-- Non-affiliates (1,804) 496 2,788 Affiliates 25,882 (1,002) (857) - - - - - - - -------------------------------------------------------------------- Total sales for resale 24,078 (506) 1,931 Other operating revenues 13,086 1,106 1,642 - - - - - - - -------------------------------------------------------------------- Total operating revenues $24,662 $(8,509) $15,288 ==================================================================== Percent change 3.9% (1.3)% 2.5% - - - - - - - --------------------------------------------------------------------
Retail revenues of $509.1 million in 1998 decreased $12.5 million or 2.4 percent from the prior year due primarily to the recovery of lower fuel costs. The price per ton of coal, which is the Company's primary fuel source, was lower in 1998 as the costs related to prior year coal contract renegotiations were fully amortized and a major coal contract price was reduced. See Note 5 to the financial statements under "Fuel Commitments" for further information. Retail revenues for 1997 decreased $9.1 million or 1.7 percent when compared to 1996 due primarily to a decrease in residential revenues as a result of mild weather and recovery of lower purchased power capacity costs.
The decrease in regulatory cost recovery and other retail revenues is primarily attributable to the recovery of decreased fuel costs as mentioned previously. Regulatory cost recovery and other includes 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 $104.5 million in 1998, an increase of $24.1 million or 29.9 percent over 1997 due to additional energy sales to affiliated companies, which is discussed below. 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:
1998 1997 1996 ---------------------------------------- (in thousands) Capacity $22,503 $24,899 $25,400 Energy 14,556 18,160 19,804 - - - - - - - ------------------------------------------------------------- Total $37,059 $43,059 $45,204 =============================================================
Declining capacity revenues reflect the decline in net plant investment related to these sales.
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 increased in 1998 due primarily to adjustments to reflect differences 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 1998 Annual Report
Kilowatt-hour sales for 1998 and the percent changes by year were as follows:
KWH Percent Change ------------- ------------------------------ 1998 1998 1997 1996 ------------- ------------------------------ (millions) Residential 4,437 7.7% (1.0)% 3.6% Commercial 3,112 7.4 3.2 3.7 Industrial 1,834 (3.7) 5.3 0.7 Other 19 4.7 1.6 2.7 ------------- Total retail 9,402 5.2 1.6 3.0 Sales for resale Non-affiliates 1,342 (12.4) (0.2) 9.9 Affiliates 1,758 107.3 19.5 (6.5) ------------- Total 12,502 10.5 2.5 3.3 =================================================================
In 1998, total retail energy sales increased due to higher temperatures when compared to the milder-than-normal temperatures in 1997 and due to increases in the number of residential and commercial customers. The decrease in industrial energy sales in 1998 when compared to 1997 primarily reflects the shut down of a major industrial customer's plant site and temporary production delays of other industrial customers. In 1997, residential energy sales declined as a result of the milder weather when compared with more normal weather in 1996. The increase in industrial energy sales was primarily the result of the Real-Time-Pricing program. The price structure of this program has encouraged participating industrial customers to lower their peak demand requirements and increase their purchases of energy during off-peak periods. 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).
Decreases in energy sales for resale to non-affiliates of 12.4 percent in 1998 when compared to 1997 and 0.2 percent in 1997 when compared to 1996 are 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 as mentioned previously.
Expenses
Total operating expenses in 1998 increased $25.6 million or 4.8 percent from the amount recorded in 1997 due primarily to higher fuel, purchased power, and maintenance expenses, offset by lower other operation expenses. In 1997, total operating expenses decreased $3.9 million or 0.7 percent from 1996. The decrease was due to lower fuel, purchased power, and maintenance expenses, offset by higher other operation expenses and depreciation and amortization expenses.
Fuel expenses in 1998 when compared to 1997 increased $16.6 million or 9.2 percent due to increased generation resulting from a higher demand for energy, while average fuel costs decreased as noted below. In 1997, fuel expenses decreased when compared to 1996 due to slightly lower fuel costs.
Purchased power expenses increased in 1998 by $6.9 million or 18.8 percent above 1997 amounts due to an increased demand for energy. In 1997, purchased power expenses decreased $6.5 million or 14.9 percent from the amount recorded in 1996. This change was due primarily to a reduction in the cost of purchased power from affiliated companies.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1998 1997 1996 ------------------------------- Total generation (millions of kilowatt-hours) 11,986 10,435 10,214 Sources of generation (percent) Coal 98.0 99.6 99.5 Oil and gas 2.0 0.4 0.5 Average cost of fuel per net kilowatt-hour generated (cents)-- 1.69 1.99 2.02 - - - - - - - ---------------------------------------------------------------------
Other operation expenses decreased $7.3 million or 5.7 percent in 1998 due to a decrease in the amortization costs of prior year payments related to renegotiations of coal supply contracts. This decrease was partially offset by higher implementation costs of a new customer accounting system, increased costs related to the Year 2000 program, and an increase in the accrual to the accumulated provision for property damage. In 1997, other operation expenses increased $11.1 million or 9.6 percent from the 1996 level. This change was attributable to higher amortization costs of prior year payments related to renegotiations of coal supply contracts, implementation costs related to a new customer accounting system, and increased production and distribution costs
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1998 Annual Report
related to 1997 work force reduction programs. See Note 2 to the financial statements under "Workforce Reduction Programs" for further discussion.
Maintenance expenses in 1998 rose by $9.3 million or 19.4 percent, as compared to 1997, due primarily to scheduled maintenance performed at Plant Crist and Plant Smith and increased transmission and distribution maintenance. In 1997, maintenance expenses decreased $3.1 million or 6.0 percent when compared to the prior year due to a decrease in scheduled maintenance of production facilities.
Interest on long-term debt in 1998 decreased $2.0 million or 9.1 percent from 1997 due primarily to a decrease in interest expense on pollution control bonds refinanced in 1997 and two long-term bank notes that matured in 1998. This decrease was partially offset by an increase in interest due to two first mortgage bonds maturing in 1998 being replaced with senior notes at a slightly higher interest rate. In 1997, interest on long-term debt decreased $3.0 million or 12.1 percent from the prior year as a result of retirements and refinancings.
Distributions on preferred securities increased $3.2 million in 1998. This increase was attributable to the issuance of $45 million of trust preferred securities in January 1998 to replace preferred stock. In 1997, distributions on preferred securities increased $2.8 million due to the issuance of $40 million of trust preferred securities in January 1997.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its cost of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with a 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 potential. The level of future earnings depends on numerous factors ranging from energy sales growth to a potentially less regulated and more competitive environment.
Gulf Power 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 the fourth quarter of 1998, the FPSC opened a docketed proceeding to consider whether the rate of return authorized for another investor-owned electric utility subject to the FPSC's jurisdiction continues to be reasonable under current market conditions. Although no official action has been taken by the FPSC at this time with regard to the authorized returns for Gulf Power or any of the other investor-owned electric utilities subject to the FPSC's jurisdiction, a similar investigation could be initiated by action of the FPSC or its staff at any time.
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 Company is positioning the business to meet the challenge of this major change in the traditional practice of selling electricity. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1998 Annual Report
commercial customers and sell energy generation to other utilities. The Company has and will continue to evaluate opportunities to partner and participate in profitable cogeneration projects. In 1998, partnering with one of the Company's largest industrial customers, construction was completed on 15 megawatts of Company-owned cogeneration on the customer's plant site. 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.
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 the 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 various restructuring and competition initiatives have been or are being discussed in Florida, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. 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 of the Company. 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, unless the Company remains a low-cost producer and provides quality service, the Company's retail 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 FPSC will set new conservation goals and approve programs to accomplish the goals by year-end 1999. Conservation goals are set every five years for a ten-year period. The last conservation goals proceeding was in 1994 and established demand-side management programs and conservation goals for 1995 to 2004. In the previous and current goals proceedings, the emphasis remains on using price flexibility and competitive offerings of energy efficient products and services. The new goals will be for the 2000 to 2009 period.
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 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1998 Annual Report
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, 1998, 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, 1998, a near-term 100 basis point change in interest rates would not materially affect the Company's financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by the year 2000. This statement establishes accounting and reporting standards for derivative instruments - including certain derivative instruments embedded in other contracts - and for hedging activities. Adoption of this statement is not expected to have a material impact on the Company's financial statements.
In March 1998, the American Institute of Certified Public Accountants (AICPA) issued a new Statement of Position, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement requires capitalization of certain costs of internal-use software. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the Costs of Start-up Activities. This statement requires that the costs of start-up activities and organizational costs be expensed as incurred. Any of these costs previously capitalized by a company must be written off in the year of adoption. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The EITF requires that energy trading contracts must be marked to market through the income statement, with gains and losses reflected rather than revenues and purchased power. Energy trading contracts are defined as energy contracts entered into with the objective of generating profits on or from exposure to shifts or changes in market prices. The Company adopted the required accounting in January 1999, and it is not expected to have a material impact on the financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s shortened the year portion of date entries to just two digits. Computers assumed, in effect, that all years began with "19." This practice was widely adopted and hard-coded into computer chips and processors found in some equipment. This approach, intended to save processing time and storage space, was used until the mid-1990s. Unless corrected before the year 2000, affected software systems and devices containing a chip or microprocessor with date and time functions could incorrectly process dates or the systems may cease to function.
The Company depends on complex computer systems for many aspects of its operations, which include generation, transmission, and distribution of electricity, as well as other business support activities. The Company's goal is to have critical devices or software that are required to maintain operations to be Year 2000 ready by June 1999. Year 2000 ready means that a system or application is determined suitable for continued use through the Year 2000 and beyond. Critical systems include, but are not limited to, turbine generator systems, control center computer systems, customer service systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000 challenge and has dedicated what it believes to be adequate resources to address the issue. The Millennium Project is a team of employees, IBM consultants, and other contractors whose progress is reviewed on a monthly basis by a steering committee of Southern Company executives.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1998 Annual Report
The work was divided into two phases. Phase I began in 1996 and consisted of identifying and assessing corporate assets related to software systems and devices that contain a computer chip or clock. The first phase was completed in June 1997. Phase 2 consists of testing and remediating high priority systems and devices. Also, contingency planning is included in this phase. Completion of Phase 2 is targeted for June 1999. The Millennium Project will continue to monitor the affected computer systems, devices, and applications into the Year 2000.
Southern Company has completed more than 70 percent of the activities contained in its work plan. The percentage of completion and projected completion dates by function are as follows:
- - - - - - - ------------------------------------------------------------------ Work Plan ----------------------------------------- Remediation Project Inventory Assessment Testing Completion - - - - - - - ------------------------------------------------------------------ Generation 100% 100% 70% 6/99 - - - - - - - ------------------------------------------------------------------ Energy Management 100 100 90 6/99 - - - - - - - ------------------------------------------------------------------ Transmission and Distribution 100 100 100 1/99 - - - - - - - ------------------------------------------------------------------ Telecommunications 100 100 50 6/99 - - - - - - - ------------------------------------------------------------------ Corporate Applications 100 100 90 3/99 - - - - - - - ------------------------------------------------------------------
Year 2000 Costs
The Company's current projected total costs for Year 2000 readiness are approximately $4.8 million. These costs include labor necessary to identify, test, and renovate affected devices and systems. From its inception through December 31, 1998, the Year 2000 program costs, recognized as expense, amounted to $3.0 million, of which $2.5 million was recorded in 1998.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of service interruptions related to the Year 2000. The Company believes, based on current tests, that the system can provide customers with electricity. These tests increase confidence, but do not guarantee error-free operation. The Company is taking what it believes to be prudent steps to prepare for the Year 2000, and it expects any interruptions in service that may occur within the Company's service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe than the scenarios that its electric system is routinely prepared to handle. The most likely worst case scenario consists of the service loss of one of the largest generating units and/or the service loss of any single bulk transmission element in its service territory. The Company has followed a proven methodology for identifying and assessing software and devices containing potential Year 2000 challenges. Remediation and testing of those devices are in progress. Following risk assessment, the Company is preparing contingency plans as appropriate and is participating in North American Electric Reliability Council - - - - - - - - coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third parties that provide goods and services crucial to the Company's operations. Among such critical third parties are fuel, transportation, telecommunications, water, chemical, and other suppliers. Contingency plans based on the assessment of each third party's ability to continue supplying critical goods and services to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical demand by customers because of their own Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled at developing and using contingency plans in unusual circumstances. As part of Year 2000 business continuity and contingency planning, the Company is drawing on that experience to make risk assessments and is developing additional plans to deal specifically with situations that could arise relative to Year 2000 challenges. The Company is identifying critical operational locations, and key employees will be on duty at those locations during the Year 2000 transition. In September 1999, drills are scheduled to be conducted to test contingency plans. Because of the level of detail of the contingency planning process, management feels that the contingency plans will keep any service interruptions that may occur within the Company's service territory isolated and short in duration.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1998 Annual Report
FINANCIAL CONDITION
Overview
The Company's financial condition continues to be very solid. During 1998, gross property additions were $69.7 million. Funds for the property additions were provided by internal sources. See the Statements of Cash Flows for further details.
Financing Activities
In 1998, the Company sold $45 million of trust preferred securities and $50 million of senior insured quarterly notes. Retirements, including maturities during 1998, totaled $45 million of first mortgage bonds, $9.5 million of preferred stock, and $8.3 million of long-term bank notes. The proceeds from the issuance of $45 million of trust preferred securities were used to repay short-term indebtedness that was used to redeem preferred stock tendered at the end of 1997 and to redeem additional preferred stock during 1998. This refinancing will result in savings of approximately $0.6 million annually. See the Statements of Cash Flows for further details.
Composite financing rates for the years 1996 through 1998 as of year end were as follows:
1998 1997 1996 ----------------------------- Composite interest rate on long-term debt 6.1% 5.9% 6.1% Composite rate on trust preferred securities 7.3% 7.6% - Composite preferred stock dividend rate 5.1% 6.1% 6.4% - - - - - - - -----------------------------------------------------------------
The composite interest rate on long-term debt increased in 1998 primarily as a result of the maturity of two low-cost first mortgage bond issues, which were replaced with long-term notes with a slightly higher interest rate. The decrease in the composite preferred stock dividend rate in 1998 was primarily due to the retirement of higher-cost preferred stock.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $434 million for the three years beginning in 1999 ($72 million in 1999, $100 million in 2000, and $262 million in 2001). Actual construction costs may vary from this estimate because of changes in such factors as: 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. The Company has budgeted $263.6 million for the years 1999 through 2002 for the estimated cost of a 532 megawatt combined cycle gas 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, subject to regulatory approval. The Company will continue its program to maintain and upgrade transmission and distribution facilities and generating plants.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $27 million will be required by the end of 2001 in connection with maturities of long-term debt. Also, 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 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 are required in two phases. Phase I compliance began in 1995 and initially affected 28 generating units of Southern Company. As a result of Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
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 $300 million for Southern Company, including approximately $42 million for Gulf Power.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1998 Annual Report
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as required to meet Phase II limits. Current compliance strategy for Phase II and ozone non-attainment could require total estimated construction expenditures for Southern Company of approximately $70 million, of which $16 million remains to be spent. Phase II compliance is not expected to have a material impact on Gulf Power.
Following adoption of legislation in April of 1992 allowing electric utilities in Florida to seek FPSC approval of their Clean Air Act Compliance Plans, Gulf Power filed its petition for approval. The FPSC approved the Company's plan for Phase I compliance, deferring until a later date approval of its Phase II Plan.
In 1993, the Florida Legislature adopted legislation that allows a utility to petition the FPSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The legislation is discussed in Note 3 to the financial statements under "Environmental Cost Recovery." Substantially all of the costs for the Clean Air Act and other new environmental legislation discussed below are expected to be recovered through the Environmental Cost Recovery Clause.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. In September 1998, the EPA issued the final regional nitrogen oxide rules to the states for implementation. The states have one year to adopt and implement the new rules. The final rules affect 22 states including Alabama and Georgia. See Note 6 to the financial statements under "Joint Ownership Agreements" related to the Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3. The EPA rules are being challenged in the courts by several states and industry groups. Implementation of the final state rules could require substantial further reductions in nitrogen oxide emissions from fossil-fired generating facilities and other industry in these states. Implementation of the standards could result in significant additional compliance costs and capital expenditures that cannot be determined until the results of legal challenges are known and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are 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 new standards will depend on the development and implementation of applicable regulations.
Gulf Power 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, 1998, the Company had approximately $1.0 million of cash and cash equivalents and $35.5 million of unused committed lines of credit with banks to meet its short-term cash needs. Refer to Statements of Cash Flows for
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1998 Annual Report
details related to the Company's financing activities. See Note 5 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. In this regard, the Company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur.
If the Company chooses to issue first mortgage bonds or preferred stock, it 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
Gulf Power Company's 1998 Annual Report contains forward-looking and historical information. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking information; accordingly, there can be no assurance that such indicated results will be realized. These factors include legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry; 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 internal restructuring--that may be pursued by the company; state and federal rate regulation; Year 2000 issues; changes in or application of environmental and other laws and regulations to which the Company is subject; political, legal and economic conditions and developments; financial market conditions and the results of financing efforts; changes in commodity prices and interest rates; weather and other natural phenomena; and other factors discussed in the reports--including Form 10-K--filed from time to time by the Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 1998 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 operating companies, a system service company, Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), and other direct and indirect subsidiaries. The operating companies (Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric) provide electric service in four southeastern states. Gulf Power Company provides electric service to the northwest panhandle of Florida. Contracts among the operating companies -- dealing with jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants.
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 generally accepted accounting principles and complies with the accounting policies and practices prescribed by the FPSC. The preparation of financial statements in conformity with generally accepted accounting principles 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.
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:
1998 1997 -------------------------- (in thousands) Deferred income tax debits $ 25,308 $ 26,586 Deferred loss on reacquired debt 18,883 20,494 Environmental remediation 7,076 7,338 Current & deferred coal contract costs - 4,456 Vacation pay 4,035 4,057 Accumulated provision for property damage (1,605) - Deferred storm charges - 703 Regulatory clauses under (over) recovery, net 3,700 (3,387) Deferred income tax credits (52,465) (56,935) Other, net (480) (629) - - - - - - - ------------------------------------------------------------------ Total $ 4,452 $ 2,683 ==================================================================
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 net 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.
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NOTES (continued) Gulf Power Company 1998 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company currently operates as a vertically integrated utility providing electricity to retail customers within its service area located in northwest Florida and to wholesale customers in the Southeast. Revenues, less affiliated transactions, by type of service were as follows:
1998 1997 1996 ------------------------------------- (in thousands) Retail $509,118 $521,620 $530,729 Wholesale 61,893 63,697 63,201 Other operating 36,865 23,779 22,673 - - - - - - - --------------------------------------------------------------- Total $607,876 $609,096 $616,603 ===============================================================
The Company accrues revenues for service rendered but unbilled at the end of each fiscal period. 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.
Fuel costs are expensed as the fuel is used. The Company's electric rates include provisions to periodically adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company also has similar 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.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.8 percent in 1998 and 3.6 percent in 1997 and 1996. The increase in 1998 is attributable to new depreciation rates, which were approved by the FPSC 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. 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.
Utility Plant
Utility plant 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, 1998 $344,341 $357,100 At December 31, 1997 $350,320 $356,766 Capital trust preferred securities: At December 31, 1998 $85,000 $89,400 At December 31, 1997 $40,000 $40,800 - - - - - - - --------------------------------------------------------------
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 1998 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 $1.3 million and $1.4 million at December 31, 1998 and 1997, respectively, is included in miscellaneous 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 storm 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, 1998, the accumulated provision for property damage was $1.6 million. In 1995, the FPSC approved the Company's request to increase the amount of its annual accrual to the accumulated provision for property damage account from $1.2 million to $3.5 million and approved 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, when the Company believes it is in a position to do so, until the account balance reaches $12 million. The Company accrued $6.5 million in 1998 and $3.9 million in 1997 to the accumulated provision for property damage. Charges to the provision account during 1998 totaled $4.2 million, which included $3.4 million related to Hurricane Georges.
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 deductible under federal income tax regulations or to the extent required by the Company's regulatory commissions. In 1998, the Company adopted FASB Statement No. 132, Employers' Disclosure about Pensions and Other Postretirement Benefits. The measurement date 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 --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $130,794 $123,467 Service cost 4,107 3,897 Interest cost 9,572 9,301 Benefits paid (6,663) (4,852) Actuarial loss (gain) and employee transfers 5,202 (1,019) - - - - - - - --------------------------------------------------------------- Balance at end of year $143,012 $130,794 ===============================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $222,196 $191,152 Actual return on plan assets 1,310 35,886 Benefits paid (6,663) (4,852) Employee transfers (3,909) 10 - - - - - - - --------------------------------------------------------------- Balance at end of year $212,934 $222,196 ===============================================================
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NOTES (continued) Gulf Power Company 1998 Annual Report
The accrued pension costs recognized in the Balance Sheet were as follows:
1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Funded status $ 69,922 $ 91,402 Unrecognized transition obligation (5,043) (5,764) Unrecognized prior service cost 4,869 5,244 Unrecognized net gain (55,978) (80,497) - - - - - - - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 13,770 $ 10,385 ===============================================================
Components of the plan's net periodic cost were as follows:
1998 1997 1996 - - - - - - - ----------------------------------------------------------------- Service cost $ 4,107 $ 3,897 $ 3,880 Interest cost 9,572 9,301 9,129 Expected return on plan assets (14,827) (13,675) (13,410) Recognized net gain (1,891) (1,656) (1,248) Net amortization (347) (347) (443) - - - - - - - ----------------------------------------------------------------- Net pension income $ (3,386) $ (2,480) $ (2,092) =================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits were:
1998 1997 - - - - - - - ---------------------------------------------------------- Discount 6.75% 7.50% Annual salary increase 4.25% 5.00% Long-term return on plan assets 8.50% 8.50% - - - - - - - ----------------------------------------------------------
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $39,669 $33,656 Service cost 946 896 Interest cost 3,123 2,845 Benefits paid (1,068) (1,077) Actuarial loss and employee transfers 3,614 3,349 Amendments 3,019 - - - - - - - - --------------------------------------------------------------- Balance at end of year $49,303 $39,669 ===============================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $9,455 $7,996 Actual return on plan assets 54 1,407 Employer contributions 1,162 1,129 Benefits paid (1,068) (1,077) - - - - - - - --------------------------------------------------------------- Balance at end of year $9,603 $9,455 ===============================================================
The accrued postretirement costs recognized in the Balance Sheet were as follows:
1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Funded status $(39,700) $(30,214) Unrecognized transition obligation 5,079 5,435 Unrecognized prior service cost 2,900 - Unrecognized net loss 8,187 4,288 - - - - - - - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(23,534) $(20,491) ===============================================================
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NOTES (continued) Gulf Power Company 1998 Annual Report
Components of the plan's net periodic cost were as follows:
1998 1997 1996 - - - - - - - --------------------------------------------------------------- Service cost $ 946 $ 896 $ 939
Interest cost 3,123 2,845 2,330 Expected return on plan assets (717) (641) (565) Transition obligation 356 356 356 Prior service cost 119 - - Recognized net loss 128 184 86 - - - - - - - --------------------------------------------------------------- Net postretirement cost $3,955 $3,640 $3,146 ===============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.30 percent for 1998, decreasing gradually to 4.75 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, 1998 as follows (in thousands):
1 Percent 1 Percent Increase Decrease - - - - - - - ------------------------------------------------- ------------- Benefit obligation $3,808 $(3,218) Service and interest costs $319 $(261) ===============================================================
Work Force Reduction Programs
The Company recorded costs related to work force reduction programs of $2.8 million in 1998, $1.4 million in 1997, and $1.2 million in 1996. The Company has also incurred its pro rata share for the costs of affiliated companies' programs. The costs related to these programs were $0.2 million for 1998, $1.3 million for 1997, and $2.1 million for 1996. The Company has expensed all costs related to these work force reduction programs.
3. LITIGATION AND REGULATORY MATTERS
FERC Review of Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of the administrative law judge's opinions in two proceedings in which the return on common equity component of formula rates contained in substantially all of the Company's wholesale power contracts was being challenged as unreasonably high. These orders resulted in no change in the wholesale power contracts that were the subject of such proceedings. The FERC also dismissed a complaint filed by three customers under long-term power sales agreements seeking to lower the equity return component in such agreements. These customers have filed applications for rehearing regarding each FERC order. In response to a requirement of the September 1998 FERC order, Southern Company filed a new equity return component on the long-term power sales contracts, to be effective January 5, 1999. The proposed equity return was lowered from 13.75 percent to 12.50 percent. The estimated impact on the Company's revenues at a 12.50% equity return would be approximately $0.8 million annually. The FERC placed the new rates into effect subject to refund. Also, this filing was consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to initiate a new proceeding regarding the equity return and other issues involving the Company's formula rate contracts. The motion was submitted pursuant to review procedures applicable to these contracts, and would be applicable to billings under such contracts on and after January 1, 1999.
Environmental Cost Recovery
In April 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 January 1994, the FPSC approved the Company's initial petition under the ECRC for recovery of environmental costs. Initially, recovery under the ECRC was determined semi-annually. The FPSC approved annual recovery periods beginning with the October 1996 through September 1997 period. As of January 1999, the annual recovery period will be on a calendar-year basis as approved by the FPSC in May 1998. Recovery includes a true-up of the prior period and a projection of the ensuing period. During 1998 and 1997, the Company recorded ECRC revenues of $15.1 million and $10.2 million, respectively.
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NOTES (continued) Gulf Power Company 1998 Annual Report
At December 31, 1998, the Company's liability for the estimated costs of environmental remediation projects for known sites was $7.1 million. These estimated costs are expected to be expended from 1999 through 2005. These projects have been approved by the FPSC for recovery through the ECRC discussed above. Therefore, the Company recorded $1.7 million in current assets and current liabilities and $5.4 million in deferred assets and liabilities representing the future recoverability of these costs.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $72 million in 1999, $100 million in 2000, and $262 million in 2001. 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, 1998, significant purchase commitments were outstanding in connection with the construction program. The Company has budgeted $263.6 million for the years 1999 through 2002 for the estimated cost of a 532 megawatt combined cycle gas 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, subject to regulatory approval. The Company will continue its construction program related to transmission and distribution facilities and the upgrading and extension of the useful lives of generating plants.
See Management's Discussion and Analysis under "Environmental Matters" for information on the impact of the Clean Air Act Amendments of 1990 and other environmental matters.
5. FINANCING AND COMMITMENTS
General
Current projections indicate that funds required for construction and other purposes, including compliance with environmental regulations, will be derived from operations; the sale of additional first mortgage bonds, long-term unsecured debt, pollution control bonds, and preferred securities; bank notes; and capital contributions from Southern Company. In addition, the Company may issue additional long-term debt and preferred securities primarily for debt maturities and redemptions of higher-cost securities.
Bank Credit Arrangements
At December 31, 1998, the Company had $41.5 million of lines of credit with banks subject to renewal June 1 of each year, of which $35.5 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 thirteen major money center banks that total $205 million, of which $25.5 million was committed at December 31, 1998.
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 1998 Annual Report
Fuel 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. Total estimated long-term obligations at December 31, 1998, including the Company's portion relating to jointly owned facilities, were as follows:
Year Fuel --------- ---------------- (in millions) 1999 $132 2000 88 2001 79 2002 78 2003 83 2004 - 2008 359 ---------------------------------------------------------- Total commitments $819 ==========================================================
In 1988, the Company made an advance payment of $60 million to a coal supplier under an arrangement to lower the cost of future coal purchased under an existing contract. This payment was fully amortized to expense on a per ton basis as of March 1998.
In December 1995, the Company made another payment of $22 million to the same coal supplier under an arrangement to lower the cost of future coal and/or to suspend the purchase of coal under an existing contract for 25 months. This payment was fully amortized to expense on a per ton basis as of March 1998.
The amortization expense of these contract renegotiations was recovered through the fuel cost recovery clause discussed under "Revenues and Regulatory Cost Recovery Clauses" in Note 1.
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 $2.8 million in 1998, and $2.3 million in 1997. The annual amounts for 1999 through 2003 are expected to be $2.8 million, $2.1 million, $1.7 million, $1.7 million, and $1.7 million respectively, and after 2003 are expected to total $16.1 million.
6. 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 an 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 an 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.
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NOTES (continued) Gulf Power Company 1998 Annual Report
At December 31, 1998, 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 $185,497(1) $224,907 Accumulated Depreciation $62,255 $113,327 Construction Work in Progress $615 $8,686
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
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual agreements for the sale of capacity and energy 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 $22.5 million in 1998, $24.9 million in 1997, and $25.4 million in 1996. See Note 3 to the financial statements under "FERC Review of Equity Returns."
Unit power from specific generating plants of Southern Company is currently being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority (JEA), and the City of Tallahassee, Florida. Under these agreements, 214 megawatts of net dependable capacity were sold by the Company during 1998, and sales will remain at that level until the expiration of the contracts in 2010, unless reduced by FPC, FP&L, and JEA after 2002.
Capacity and energy sales to FP&L, the Company's largest single customer, provided revenues of $22.3 million in 1998, $25.4 million in 1997, and $27.2 million in 1996, or 3.4 percent, 4.1 percent, and 4.3 percent of operating revenues, respectively.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets to be recovered from customers were $25.3 million. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. At December 31, 1998, the tax-related regulatory liabilities to be credited to customers were $52.5 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:
1998 1997 1996 ------------------------------------ (in thousands) Total provision for income taxes: Federal-- Currently payable $31,746 $34,522 $31,022 Deferred--current year 18,485 19,297 26,072 --reversal of prior years (22,952) (25,778) (24,780) - - - - - - - -------------------------------------------------------------------- 27,279 28,041 32,314 - - - - - - - -------------------------------------------------------------------- State-- Currently payable 5,137 5,975 4,394 Deferred--current year 2,745 2,868 3,904 --reversal of prior years (2,962) (3,434) (3,039) - - - - - - - -------------------------------------------------------------------- 4,920 5,409 5,259 - - - - - - - -------------------------------------------------------------------- Total 32,199 33,450 37,573 Less income taxes credited to other income (1,890) (1,584) (248) - - - - - - - -------------------------------------------------------------------- Total income taxes charged to operations $34,089 $35,034 $37,821 ====================================================================
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NOTES (continued) Gulf Power Company 1998 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
1998 1997 -------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $155,833 $156,328 Property basis differences 20,330 19,220 Other 17,645 14,242 - - - - - - - --------------------------------------------------------------------- Total 193,808 189,790 - - - - - - - --------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 9,509 9,268 Postretirement benefits 7,644 6,976 Other 10,702 10,861 - - - - - - - --------------------------------------------------------------------- Total 27,855 27,105 - - - - - - - --------------------------------------------------------------------- Net deferred tax liabilities 165,953 162,685 Less current portion, net (165) (3,617) ===================================================================== Accumulated deferred income taxes in the Balance Sheets $166,118 $166,302 =====================================================================
Deferred investment tax credits are amortized over the life 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 1998, $2.2 million in 1997, and $2.3 million in 1996. At December 31, 1998, 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:
1998 1997 1996 ---------------------------- 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) (1) (1) Other, net (2) (4) (2) - - - - - - - ---------------------------------------------------------------- Effective income tax rate 36% 35% 37% ================================================================
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. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
9. 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.
10. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirement and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
1998 1997 ---------------------- (in thousands) Bond improvement fund requirement $ 850 $1,300 Less portion to be satisfied by certifying property additions 850 1,300 - - - - - - - ----------------------------------------------------------------- Cash requirement - - Maturities of first mortgage bonds - 45,000 Current portion of other long-term debt 27,000 8,327 - - - - - - - ----------------------------------------------------------------- Total $27,000 $53,327 =================================================================
The first mortgage bond improvement fund requirement amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to
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NOTES (continued) Gulf Power Company 1998 Annual Report
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.
11. 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, 1998, retained earnings of $127 million were restricted against the payment of cash dividends on common stock under the terms of the mortgage indenture.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1998 and 1997 are as follows:
Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock - - - - - - - -------------------------------------------------------------------- (in thousands) March 1998 $140,950 $15,237 $ 6,853 June 1998 177,130 23,742 13,364 September 1998 199,377 34,070 26,989 December 1998 133,061 15,216 9,315
March 1997 $141,374 $20,212 $10,740 June 1997 145,292 19,153 10,386 September 1997 193,710 34,750 27,484 December 1997 145,480 15,068 9,000 - - - - - - - --------------------------------------------------------------------
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 1998 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 generally accepted accounting principles appropriate in the circumstances 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 books and records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based upon a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting control maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an ongoing basis by the 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 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 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 generally accepted accounting principles.
/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
February 10, 1999
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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, 1998 and 1997, and the related statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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-167 through II-182) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Arthur Andersen LLP
Atlanta, Georgia February 10, 1999
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's 1998 net income after dividends on preferred stock was $55.1 million, reflecting a 2.0 percent or $1.1 million increase over the prior year. This change is primarily attributable to higher retail and wholesale revenues. In 1997, earnings were $54.0 million, up $1.3 million from the prior year. This earnings increase resulted primarily from lower operating expenses.
Revenues
The following table summarizes the factors impacting operating revenues for the past three years:
Increase (Decrease) From Prior Year ------------------------------------- 1998 1997 1996 ------------------------------------- (in thousands) Retail -- Change in base rates (PEP and ECO Plan) $ 335 $ 3,177 $ (402) Sales growth 4,787 109 11,187 Weather 7,091 (1,118) (5,585) Fuel cost recovery and other 13,112 948 (1,255) ----------------------------------------------------------------- Total retail 25,325 3,116 3,945 ---------------------------------------------------- ------------ Sales for resale -- Non-affiliates 16,084 5,464 7,776 Affiliates 8,142 (11,606) 14,139 ----------------------------------------------------------------- Total sales for resale 24,226 (6,142) 21,915 Other operating revenues 1,992 2,585 1,616 ----------------------------------------------------------------- Total operating revenues $51,543 $ (441) $27,476 ================================================================= Percent change 9.5% (0.1)% 5.3% -----------------------------------------------------------------
Retail revenues of $443 million in 1998 increased 6.1 percent from 1997. Continued growth in the service area and the positive impact of weather on energy sales were the predominant factors contributing to the rise in revenues. Retail revenues for 1997 reflected a 0.8 percent increase over the prior year due to the 1996 Performance Evaluation Plan (PEP) retail rate increase and the January 1997 Environmental Compliance Overview Plan (ECO Plan) retail rate increase. Changes in base rates reflect any rate changes made under the PEP and ECO Plan.
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 9.8 percent in 1998 and 3.6 percent in 1997, with the related revenues rising 11.3 percent and 1.6 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to Mississippi Power's. Revenues from other sales outside the service area increased in 1998 and 1997 primarily due to power marketing activities. These increases were primarily 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 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
Below is a breakdown of kilowatt-hour sales for 1998 and the percent change for the last three years:
1998 Percent Change ----------- ------------------------------ KWH 1998 1997 1996 (in millions) Residential 2,249 10.3% (2.0)% 1.9% Commercial 2,623 9.0 4.0 3.3 Industrial 3,729 (6.4) 0.6 3.8 Other 40 - 2.6 1.9 ---------- Total retail 8,641 2.0 0.9 3.2 Sales for Resale -- Non-affiliates 3,158 9.1 6.2 9.4 Affiliates 552 15.2 (31.0) 184.7 ---------- Total 12,351 4.3 0.2 8.7 ==================================================================
Residential and commercial sales increased in 1998 10.3 percent and 9.0 percent respectively, and industrial sales decreased 6.4 percent. The increases can be attributed primarily to sales growth and hotter temperatures in the summer months. The decrease in industrial sales was due primarily to a large industrial customer being out of service because of damages incurred from Hurricane Georges. Residential sales in 1997 declined 2.0 percent while sales to commercial and industrial customers increased by 4.0 percent and 0.6 percent, respectively. Milder-than-normal temperatures experienced in 1997 contributed to the moderate sales.
The Company anticipates continued growth in energy sales as the economy improves within its service area. The casino industry and ancillary services, such as lodging, food, transportation, etc., are some of the factors that may influence the economy of the Company's service area. Also, energy demand is expected to grow as a result of a larger and more fully employed population.
Expenses
Total operating expenses were $515 million in 1998 reflecting an increase of $49.1 million or 10.6 percent over the prior year. The increase was due primarily to higher fuel expenses, higher maintenance and higher other operation costs. In 1997, total operating expenses decreased by 0.3 percent from the prior year due primarily to lower administrative and general expenses.
Fuel costs are the single largest expense for the Company. Fuel expenses in 1998 increased 10.2 percent due to a 3.1 percent increase in generation and a higher average cost of fuel. In 1998, expenses related to purchased power from non-affiliates increased 133.0 percent and expenses related to purchased power from affiliates decreased 4.6 percent. The increased generation was due to higher demand for energy across the Southern electric system. Further, the higher demand for energy resulted in higher purchased power costs from non-affiliates.
In 1997, fuel costs increased because of a 1.1 percent increase in generation caused by the higher demand for energy in the retail sector. Expenses related to purchased power from non-affiliates decreased and expenses related to purchased power from affiliates increased due to the availability of energy within the Southern electric system.
Purchased power expense increased $18 million (128.4 percent) to meet higher territorial energy demands and power marketing activities. Energy purchased for power marketing activities was resold to non-affiliated third parties and had no significant effect on net income. Sales and purchases among Mississippi Power and its affiliates will vary from period to period depending on demand and the availability and variable production cost at each generating unit in the Southern electric system.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1998 1997 1996 ---------------------------- Total generation (millions of kilowatt hours) 10,610 10,289 10,180 Sources of generation (percent) -- Coal 80 85 85 Gas 20 15 15 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.62 1.54 1.57 ==============================================================
Other operation expenses increased 7.5 percent in 1998 primarily due to continuing expenses related to a new customer service system, modification of certain information systems for year 2000 readiness discussed below, and costs related to work force reduction programs. In 1997, other operation expense decreased 3.5 percent due to lower administrative and general expenses.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
Maintenance expenses increased 6.6 percent in 1998 due to scheduled maintenance performed at Plants Daniel and Watson, as well as other projects.
In 1998, depreciation and amortization expenses increased 4.1 percent primarily due to additional plant investment and increased amortization of regulatory assets.
Comparisons of taxes other than income taxes for 1998 and 1997 show increases of 4.4 percent and 1.1 percent, respectively, due to higher municipal franchise taxes resulting from higher retail revenues.
Effects of Inflation
Mississippi Power 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 long-lived utility plant. Conventional accounting for historical costs does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred stock. 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 regulatory matters to energy sales growth to a less regulated more competitive environment. Expenses are subject to constant review and cost control programs. See Note 2 to the financial statements under "Workforce Reduction Programs" for information regarding the Company's workforce reduction plan of 1997.
The Company currently operates as a vertically integrated company 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 MPSC under cost-based regulatory principles.
Mississippi Power is also maximizing the utility of invested capital and minimizing the need for capital by refinancing, decreasing the average fuel stockpile, raising generating plant availability and efficiency, and aggressively controlling the construction budget.
Operating revenues will be affected by any changes in rates under the PEP, the Company's performance based ratemaking plan, and the ECO Plan. PEP has proven to be a stabilizing force on electric rates, with only moderate changes in rates taking place. The ECO Plan provides for recovery of costs (including costs of capital) associated with environmental projects approved by the Mississippi Public Service Commission (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. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters."
The Federal Energy Regulatory Commission (FERC) regulates the Company's wholesale rate schedules, power sales contracts and transmission facilities. The FERC is currently reviewing the rate of return on common equity included in certain contracts and may require such returns to be lowered, possibly retroactively.
Further discussion of PEP, the ECO Plan, and proceedings before the FERC is found in Note 3 to the financial statements herein.
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 Mississippi Power's service area.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
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.
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. Restructuring initiatives are being discussed in Mississippi; none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. 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 inability of Mississippi Power 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. 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 Mississippi Power remains a low-cost producer and provides quality service, the Company's retail energy sales growth could be limited, and this could significantly erode earnings. The Company is subject to the provisions of FASB Statement 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.
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, 1998, exposure from these activities was not material to the Company's financial position, results of operation, or cash flow. Also, based on the Company's overall interest rate exposure at December 31, 1998, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No.133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by the year 2000. This statement establishes accounting and reporting standards for derivative instruments - including certain derivative instruments embedded in other contracts - and for hedging activities. The Company has not yet quantified the impact of adopting this statement on its financial statements; however, the adoption could increase volatility in earnings and other comprehensive income.
In March 1998, the American Institute of Certified Public Accountants (AICPA) issued a new Statement of Position, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement requires capitalization of certain costs of internal-use software. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the Cost of Start-up Activities. This statement requires that the costs of start-up activities and organizational costs be expensed as incurred. Any of these costs previously capitalized by a company must be written off in the year of adoption. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The EITF requires that energy trading contracts must be marked to market through the income statement, reflecting gains and losses rather than revenues and purchased power expense. Energy trading contracts are defined as energy contracts entered into with the objective of generating profits on or from exposure to shifts or changes in market prices. The Company adopted the required accounting in January 1999, and it is not expected to have a material impact on the financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s shortened the year portion of date entries to just two digits. Computers assumed, in effect, that all years began with "19." This practice was widely adopted and hard wired into computer chips and processors found in some equipment. This approach, intended to save processing time and storage space was used until the mid-1990s. Unless corrected before the year 2000, affected software systems and devices containing a chip or microprocessor with date and time function could incorrectly process dates or the systems may cease to function.
The Company depends on complex computer systems for many aspects of its operations, which include generation, transmission, and distribution of electricity, as well as other business support activities. The Company's goal is to have critical devices or software that are required to maintain operations to be Year 2000 ready by June 1999. Year 2000 ready means that a system or application is determined suitable for continued use through the Year 2000 and beyond. Critical systems include, but are not limited to, safe shutdown systems, turbine generator systems, control center computer systems, customer service systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000 challenge and has dedicated adequate resources to address the issue. The Millennium Project is a team of employees, IBM consultants, and other contractors whose progress is reviewed on a monthly basis by a steering committee of Southern Company executives.
The Company's Year 2000 Program was divided into two phases. Phase I began in 1996 and consisted of identifying and assessing corporate assets related to software systems and devices that contain a computer chip or clock. The first phase was completed in June 1997. Phase 2 consists of testing and remediating high priority systems and devices. Also, contingency planning is included in the phase. Completion of Phase 2 is targeted for June 1999. The Millennium Project will continue to monitor the affected computer systems, devices and applications into the year 2000.
The Southern Company has completed more than 70 percent of the activities in its work plan. The percentage of completion and projected completion by function is as follows:
Work Plan - - - - - - - -------------------------------------------------------------------------- Remediation Project Inventory Assessment Testing Completion - - - - - - - -------------------------------------------------------------------------- Generation 100% 100% 70% 6/99 Energy Management 100 100 90 6/99 Transmission and Distribution 100 100 100 1/99 Telecommunications 100 100 50 6/99 Corporate Applications 100 100 90 3/99 - - - - - - - --------------------------------------------------------------------------
Year 2000 Costs
Current projected costs for Year 2000 readiness are approximately $4.9 million. These costs include labor necessary to identify, test, and renovate affected devices and systems. From its inception through December 31, 1998, the year 2000 program costs, recognized as expense, amounted to $3.2 million.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of service interruptions related to Year 2000. The Company believes, based on current tests, that the system can provide customers with electricity. These tests increase confidence, but do not guarantee error-free operations. The Company is taking what it believes to be prudent steps to prepare for the Year 2000, and it expects any interruption in service that may occur within the service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe than the scenarios that its electric system is routinely prepared to handle. The most likely worst case scenario consists of the service loss of one of the largest generating units and/or the loss of any single bulk transmission element in its service territory. The Company has followed a proven methodology for identifying and assessing software and devices containing potential Year 2000 challenges. Remediation and testing of those devices are in progress. Following risk assessment, the Company is preparing contingency plans as appropriate and is participating in North American Electric Reliability Council-coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third parties that provide goods and services crucial to the Company's operations. Among such critical third parties are fuel, transportation, telecommunication, water, chemical, and other suppliers. Contingency plans based on the assessment of each third party's ability to continue supplying critical goods and services to the Company is being developed.
There is a potential for some earnings erosion caused by reduced electrical demand by customers because of their Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled at developing and using contingency plans in unusual circumstances. As part of Year 2000 business continuity and contingency planning, the Company is drawing on that experience to make risk assessments and developing additional plans to deal specifically with situations that could arise relative to Year 2000 challenges. The Company is identifying critical operational location, and key employees will be on duty at those locations during the Year 2000 transition. In September 1999, drills are scheduled to be conducted to test contingency plans. Because of the level of detail of the contingency planning process, management feels that the contingency plans will keep any service interruptions that may occur within the service territory isolated and short in duration.
FINANCIAL CONDITION
Overview
The principal change in Mississippi Power's financial condition during 1998 was gross property additions to utility plant of $68 million. Funding for gross property additions and other capital requirements has been provided from operating activities, principally earnings and the non-cash charges to income of depreciation and amortization. The Statements of Cash Flows provide additional details.
Financing Activity
The Company continued to improve its financial position by issuing pollution control bonds and retiring higher-cost issues in 1998. The Company sold $13.5 million of pollution control bonds and increased unsecured debt by $90 million. Retirements, including maturities during 1998, totaled $75 million of first mortgage bonds and $13 million of pollution control bonds. See the Statements of Cash Flows for further details.
Composite financing rates for the years 1996 through 1998 as of year-end were as follows:
1998 1997 1996 ---------------------------- Composite interest rate on long-term debt 6.14% 6.16% 6.03%
Composite preferred stock dividend rate 6.33% 6.33% 6.58%
Composite interest rate on preferred securities 7.75% 7.75% - ============================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
The decrease in the composite dividend rate on preferred stock in 1997 was primarily the result of retirements.
Capital Structure
At year-end 1998, the Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, remained at the same level as in 1997 at 52.1 percent.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $164 million ($67 million in 1999, $52 million in 2000, and $45 million in 2001). The major emphasis within the construction program will be on the upgrade of existing facilities.
In February 1999, the Company signed an interim construction agency agreement with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the Company to design and construct, as agent for Escatawpa, a 1064 megawatt natural gas combined cycle facility. On or before April 30, 1999, Escatawpa and the Company anticipate entering into an Agreement for Lease (which will supersede the interim construction agency agreement), and a Lease Agreement. It is anticipated that the total project will cost approximately $406 million, and upon project completion, the Company will lease the facility from Escatawpa. If the anticipated lease arrangement is not reached, the Company will either exercise its purchase option or Escatawpa will sell the facility to a third party.
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, and 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 $80.1 million will be required by the end of 2001 for present sinking fund requirements and maturities of long-term debt. Mississippi Power 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
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Mississippi Power and the other operating companies of Southern 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 initially affected 28 generating plants in the Southern electric system. As a result of Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
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 $65 million for Mississippi Power.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Current compliance strategy for Phase II could require total estimated construction expenditures of approximately $70 million, of which $16 million remains to be spent. Phase II compliance is not expected to have a material impact on Mississippi Power.
Mississippi Power'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. Mississippi Power'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 provision of the Clean Air Act is expected to be recovered through existing ratemaking
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. In September 1998, the EPA issued the final regional nitrogen oxide rules to the states for implementation. The states have one year to adopt and implement the new rules. The final rules affect 22 states that at present does not include Mississippi. The EPA is presently evaluating whether or not to bring an additional 15 states under this regional haze rule. Misssissippi is one of those new 15 states. The EPA rules are being challenged in the courts by several states and industry groups. Implementation of the final state rules could require substantial further reductions in nitrogen oxide emissions from fossil-fired generating facilities and other industry in these states. Implementation of the standards could result in significant additional compliance costs and capital expenditures that cannot be determined until the results of legal challenges are known and the states have adopted their final rules.
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 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. Should remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. A currently owned site where manufactured gas plant operations were located prior to the Company's ownership has been investigated for potential remediation. Remediation is scheduled for 1999. See Note 3 to the financial statements under "Environmental Compliance Overview Plan" for additional information.
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. The likelihood or outcome of such potential lawsuits cannot be determined at this time.
Sources of Capital
At December 31, 1998, the Company had $76.3 million of unused committed credit agreements. The Company had $13 million of short term notes payable outstanding at year end 1998.
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 issuances 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 issued unsecured debt in 1998. In this regard, Mississippi Power sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness the Company may incur.
Mississippi Power 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 sufficiently high enough to permit, at present interest rate levels, any foreseeable security sales. The amount of securities which the Company will be
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1998 Annual Report
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, including the foregoing Management's Discussion and Analysis, contains forward-looking and historical information. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking information; accordingly, there can be no assurance that such indicated results will be realized. These factors include legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry; 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 internal restructuring -- that may be pursued by the Company; state and federal rate regulation; changes in or application of environmental and other laws and regulations to which the Company is subject; political, legal and economic conditions and developments; financial market conditions and the results of financing efforts; changes in commodity prices and interest rates; weather and other natural phenomena; and other factors discussed in the 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 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), and Southern Energy Solutions, and other direct and indirect subsidiaries. The operating companies (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four southeastern states. Contracts among the companies--dealing with 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 to the subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy Solutions develops new business opportunities related to energy products and services.
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. Mississippi Power is also subject to regulation by the FERC and the Mississippi Public Service Commission (MPSC). The Company follows generally accepted accounting principles and complies with the accounting policies and practices prescribed by the respective commissions. The preparation of financial statements in conformity with generally accepted accounting principles 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.
Regulatory Assets and Liabilities
Mississippi Power 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 as of December 31 relate to:
1998 1997 ------------------------- (in thousands) Deferred income taxes $ 22,697 $ 21,906 Vacation pay 4,717 5,030 Workforce reduction plan of 1997 12,748 18,236 Premium on reacquired debt 9,304 9,508 Deferred environmental costs 1,500 1,583 Property damage reserve (910) (13,991) Deferred income tax credits (37,277) (38,203) Other, net (2,538) (2,982) - - - - - - - ---------------------------------------------------------------- Total $ 10,241 $ 1,087 ================================================================
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 the net regulatory assets and liabilities related to that portion of operations 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
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.
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NOTES (continued) Mississippi Power Company 1998 Annual Report
Revenues, less affiliated transactions, by type of service were as follows:
1998 1997 1996 -------------------------------------- (in thousands) Retail $442,567 $417,242 $414,126 Wholesale 121,225 105,141 99,596 Other 13,054 11,062 8,477 - - - - - - - ----------------------------------------------------------------- Total $576,846 $533,445 $522,199 - - - - - - - -----------------------------------------------------------------
Mississippi Power accrues revenues for service rendered but unbilled 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 depreciable utility plant in service is provided by using composite straight-line rates which approximated 3.3 percent in 1998, 1997, and 1996. 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 facilities.
Income Taxes
Mississippi Power 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.
Utility Plant
Utility plant is stated at original cost. This 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 charged to utility plant.
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, 1998 $343 $348 At December 31, 1997 $327 $330 Capital trust preferred securities: At December 31, 1998 $35 $36 At December 31, 1997 35 36 - - - - - - - --------------------------------------------------------------
The fair value for long-term debt and preferred securities was based on either closing market price or closing price of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when used or installed.
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NOTES (continued) Mississippi Power Company 1998 Annual Report
Provision for Property Damage
Mississippi Power 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 provided for such costs by charges to income of $1.5 million in each of the years 1998, 1997 and 1996. The cost of repairing damage resulting from such events that individually exceed $50 thousand is charged to the accumulated provision to the extent it is available. Effective January 1995, regulatory treatment by the MPSC allowed a maximum accumulated provision of $18 million.
Hurricane Georges struck Mississippi's service area on September 28, 1998, causing power outages and widespread flooding in certain counties. Current estimates place the cost of repairing Mississippi's damaged facilities at approximately $16.4 million, of which $1.5 million is expected to be recovered from insurance. Substantially all of the cost ($13.9 million) was charged to the property damage reserve; income will not be significantly affected by these restoration costs. As of December 31, 1998, the accumulated provision amounted to $0.9 million.
2. RETIREMENT BENEFITS
Mississippi Power has a defined benefit, trusteed, pension plan that covers substantially all regular 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 to the extent required by the MPSC. In 1998, the Company adopted FASB Statement No. 132 Employers' Disclosure about Pensions and Other Postretirement Benefits The measurement date 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 ---------------------------- 1998 1997 - - - - - - - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $132,131 $127,834 Service cost 3,848 4,015 Interest cost 9,613 9,407 Benefits paid (7,845) (5,384) Actuarial (gain) loss and employee transfers 5,060 (3,571) Effect of workforce reduction - (170) - - - - - - - ----------------------------------------------------------------- Balance at end of year $142,807 $132,131 =================================================================
Plan Assets ---------------------------- 1998 1997 - - - - - - - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $207,457 $179,658 Actual return on plan assets 1,252 33,718 Benefits paid (7,845) (5,385) Employee transfers (2,764) (534) - - - - - - - ----------------------------------------------------------------- Balance at end of year $198,100 $207,457 =================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1998 1997 - - - - - - - -------------------------------------------------------------------- (in thousands) Funded status $ 55,293 $ 75,326 Unrecognized transition obligation (4,359) (4,903) Unrecognized prior service cost 5,405 5,818 Unrecognized net gain (56,590) (78,936) - - - - - - - -------------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (251) $ 2,695 ====================================================================
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NOTES (continued) Mississippi Power Company 1998 Annual Report
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - ------------------------------------------------------------------ (in thousands) Service cost $ 3,848 $ 4,015 $ 3,842 Interest cost 9,613 9,407 9,310 Expected return on Plan assets (13,817) (12,805) (12,562) Recognized net gain (1,956) (1,729) (1,202) Net amortization (131) (119) (232) - - - - - - - ------------------------------------------------------------------- Net pension income $ (2,443) $ (1,231) $ (844) ===================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits were:
1998 1997 --------------------------------------------------------------- Discount 6.75% 7.50% Annual salary increase 4.25 5.00 Long-term return on plan assets 8.50 8.50 ---------------------------------------------------------------
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations ---------------------------- 1998 1997 - - - - - - - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $43,417 $41,108 Service cost 806 867 Interest cost 3,162 2,922 Benefits paid (2,302) (1,495) Actuarial loss and employee transfers 2,177 2,824 Effect of work force reduction - (2,809) - - - - - - - ----------------------------------------------------------------- Balance at end of year $47,260 $43,417 =================================================================
Plan Assets ---------------------------- 1998 1997 - - - - - - - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $12,189 $10,210 Actual return on plan assets 176 1,661 Employer contributions 2,716 1,813 Benefits paid (2,302) (1,495) - - - - - - - ----------------------------------------------------------------- Balance at end of year $12,779 $12,189 =================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
1998 1997 - - - - - - - -------------------------------------------------------------------- (in thousands) Funded status $(34,481) $(31,228) Unrecognized transition obligation 4,967 5,313 Unrecognized net loss (gain) 1,010 (1,980) Fourth quarter contributions 577 728 - - - - - - - -------------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(27,927) $(27,167) ======================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - ------------------------------------------------------------------ (in thousands) Service cost $ 806 $ 867 $ 958 Interest cost 3,162 2,922 2,830 Expected return on plan assets (989) (815) (696) Recognized net (gain) loss - (7) 18 Net amortization 346 362 362 - - - - - - - ------------------------------------------------------------------ Net postretirement cost $3,325 $3,329 $3,472 ==================================================================
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NOTES (continued) Mississippi Power Company 1998 Annual Report
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.30 percent for 1998, decreasing gradually to 4.75 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 increase the accumulated benefit obligation and the service and interest cost components at December 31, 1998 as follows:
1 Percent 1 Percent Increase Decrease - - - - - - - -------------------------------------------------- -------------- (in thousands) Benefit obligation $3,128 $(2,652) Service and interest costs 281 (236) - - - - - - - -----------------------------------------------------------------
Workforce Reduction Programs
In 1997, approximately one hundred employees of Mississippi Power accepted the terms of a workforce reduction plan. The total cost to be incurred in connection with this voluntary plan is expected to be $18.2 million, including a $2.5 million pension and postretirement benefits curtailment loss. 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. The unamortized balance of this program was $12.7 million at December 31, 1998.
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Plans
Mississippi Power'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 Mississippi Power 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 indicators that emphasize price and service to the customer. PEP provides for semiannual evaluations of Mississippi'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. In September 1996, the MPSC under PEP approved a retail revenue increase of $4.5 million (1.06 percent of annual retail revenue) which became effective in October 1996. There were no PEP retail revenue changes for 1998 or 1997.
FERC Reviews Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of its administrative law judge's opinions in two proceedings in which the return on common equity component contained in substantially all of the operating companies' wholesale formula rate contracts was being challenged as unnecessarily high. These orders resulted in no change in the wholesale contracts. The FERC also dismissed a complaint filed by the three customers under long-term power sales agreements seeking to lower the equity return component in such agreements. These customers have filed applications for rehearing regarding each FERC order. In response to a requirement of the September 1998 FERC orders, Southern Company filed a new equity return component on the long-term power sales contracts, to be effective January 5, 1999. The proposed equity return was lowered from 13.75 percent to 12.5 percent. The FERC placed the new rates into effect subject to refund. Also this filing was consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to initiate a new proceeding regarding the equity return and other issues involving the operating companies' formula rate contracts. The motion was submitted pursuant to review procedures applicable to these contracts, and would be applicable to billings under such contracts on and after January 1, 1999.
Environmental Compliance Overview Plan
The MPSC approved Mississippi Power's Environmental Compliance Overview Plan (ECO) in 1992. The 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 plan also provides for carryover of any amount over the 2 percent limit into the next year's revenue requirement. In 1997, the Company's filing with the MPSC under the ECO Plan resulted in an annual retail rate increase of $0.9 million. The 1998 ECO filing resulted in a small decrease in customer prices.
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NOTES (continued) Mississippi Power Company 1998 Annual Report
Mississippi Power 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. A currently owned site where manufactured gas plant operations were located prior to the Company's ownership is being investigated for potential remediation. In recognition of probable remediation, the Company in 1995 recorded a liability and a deferred debit (regulatory asset) of $1.8 million, including feasibility study costs. The Company recognizes such costs as they are incurred and recovers them under the ECO Plan as provided in the Company's 1995 ECO order. As of December 31, 1998, the balance in the liability and regulatory asset accounts was $1.5 million. The remedial investigation has been approved by the Mississippi Department of Environmental Quality. The site is scheduled to be remediated in 1999. The Company currently estimates the remediation costs to be approximately $1.5 million before recovery from potentially responsible parties.
Approval for New Capacity
In January of 1998, the Company was granted a Certificate of Public Convenience and Necessity by the MPSC to build approximately 1,000 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, which will lease the facility to the Company (see Note 4, Construction Program). The Company also requested approval from the MPSC to exclude the costs of the new facility from retail rate base and to assign the Company's existing generating capacity to its retail business, beginning in 2001. In January 1999, the Company and Mississippi Public Utility Staff entered a stipulation covering the details of cost allocation and ratemaking to effect this change. In February 1999, the Commission held hearings on this matter and subsequently granted the Company's request, as modified by the stipulation.
4. CONSTRUCTION PROGRAM
Mississippi Power is engaged in continuous construction programs, the costs of which are currently estimated to total $67 million in 1999, $52 million in 2000, and $45 million in 2001.
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, the upgrading of generating plants, and the addition of combined cycle generation.
In February 1999, the Company signed an interim construction agency agreement with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the Company to design and construct, as agent for Escatawpa, a 1064 megawatt natural gas combined cycle facility. On or before April 30, 1999, Escatawpa and the Company anticipate entering into an Agreement for Lease (which will supersede the interim construction agency agreement), and a Lease Agreement. It is anticipated that the total project will cost approximately $406 million. Upon project completion, the Company will lease the facility from Escatawpa. If the anticipated lease arrangement is not reached, the Company will either exercise its purchase option or Escatawpa will sell the facility to a third party.
5. FINANCING AND COMMITMENTS
Financing
Mississippi Power's construction program is expected to be financed from internal and other sources, such as the issuance of additional long-term debt and preferred securities and the receipt of capital contributions from Southern Company.
The amounts of first mortgage bonds and preferred stock that can be issued in the future will be contingent upon market conditions, adequate earnings levels, regulatory authorizations and other factors.
At December 31, 1998, Mississippi Power had total committed credit agreements with banks for $96.3 million. At year-end 1998, the unused portion of these committed credit agreements was $76.3 million. These credit agreements expire at various dates in 1999 and in 2000. 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
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NOTES (continued) Mississippi Power Company 1998 Annual Report
calendar quarter after the applicable termination date or at an earlier date at the Company's option. In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. At December 31, 1998, the Company had $13 million of short-term borrowings outstanding.
Assets Subject to Lien
Mississippi Power'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, Mississippi Power and Gulf States Utilities (now Entergy) 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 1998 use fees collected under this agreement, net of related expenses, amounted to $3.4 million each year, and are included within Other Income in the Statements of Income.
In 1989, Mississippi Power entered into a twenty-two year 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 at 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 inventory, was $2.8 million in 1998, $2.0 million in 1997, and $1.7 million in 1996. The Company's annual lease payments for 1999 through 2003 will average approximately $2.2 million and after 2003, lease payments total in aggregate approximately $16 million.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of its generating plants, Mississippi Power 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, 1998, were as follows:
Year Fuel -------- -------------- (in millions) 1999 $111 2000 80 - - - - - - - ---------------------------------------------------------- Total commitments $191 - - - - - - - ----------------------------------------------------------
Additional commitments for fuel will be required in the future to supply the Company's fuel needs.
In 1996, Mississippi Power entered into agreements to purchase options for summer peaking power for the years 1997 through 2000. The Company has purchased options from power marketers for up to 250 megawatts of peaking power in 1997; 300 megawatts in 1998; 250 megawatts in 1999; and 400 megawatts in 2000. In 1997and 1998, Mississippi Power exercised its option to purchase 250 megawatts and 300 megawatts of peaking capacity respectively. In June 1997, the MPSC approved Mississippi Power's request that it be allowed to earn a return on the capacity portion of this agreement. Mississippi Power expects to exercise its option to purchase 250 megawatts of summer peaking capacity in 1999.
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NOTES (continued) Mississippi Power Company 1998 Annual Report
6. JOINT OWNERSHIP AGREEMENTS
Mississippi Power and Alabama Power own as tenants in common Units 1 and 2 at Greene County Electric Generating Plant located in Alabama; and Mississippi Power and Gulf Power own as tenants in common Daniel Electric Generating Plant located in Mississippi.
At December 31, 1998, Mississippi Power'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% $ 60,868 $27,767
Daniel 1,000 50% 219,082 99,006 --------------------------------------------------------------------------
Mississippi Power's share of plant operating expenses is included in the corresponding operating expenses in the Statements of Income.
7. LONG-TERM POWER SALES AGREEMENTS
Mississippi Power and the other operating 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 capacity revenues have been $10,389 in 1998; $8,000 in 1997; and none in 1996.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets and liabilities were $23 million and $37 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. 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:
1998 1997 1996 ---------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $20,500 $27,651 $29,888 Deferred --current year 7,007 8,171 13,816 --reversal of prior years 2,435 (9,236) (14,913) ----------------------------------------------------------------- 29,942 26,586 28,791 ----------------------------------------------------------------- State -- Currently payable 2,544 5,537 3,588 Deferred --current year 1,568 1,756 4,727 --reversal of prior years 610 (2,499) (3,556) ----------------------------------------------------------------- 4,722 4,794 4,759 ----------------------------------------------------------------- Total 34,664 31,380 33,550 Less income taxes charged to other income 165 (588) 932 ----------------------------------------------------------------- Federal and state income taxes charged to operations $34,499 $31,968 $32,618 =================================================================
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NOTES (continued) Mississippi Power Company 1998 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities are as follows:
1998 1997 ---------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $153,768 $149,941 Basis differences 9,642 10,037 Other 26,038 25,097 --------------------------------------------------------------- Total 189,448 185,075 --------------------------------------------------------------- Deferred tax assets: Other property basis differences 22,391 23,139 Pension and other benefits 9,441 9,803 Property insurance 1,526 5,351 Unbilled fuel 2,080 802 Other 14,406 19,714 --------------------------------------------------------------- Total 49,844 58,809 --------------------------------------------------------------- Net deferred tax liabilities 139,604 126,266 Portion included in current assets, net 4,248 8,379 --------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $143,852 $134,645 ===============================================================
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 $1.2 million in 1998, $1.2 million in 1997, and $1.4 million in 1996. At December 31, 1998, 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:
1998 1997 1996 ---------------------------------- Federal statutory rate 35.00% 35.00% 35.00% State income tax, net of federal deduction 3.34 3.51 3.39 Non-deductible book depreciation .47 .47 .46 Other (1.04) (3.60) (2.05) ------------------------------------------------------------------ Effective income tax rate 37.77% 35.38% 36.80% ==================================================================
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. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
9. 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 Mississippi Power Capital Trust for the obligation with respect to the preferred securities.
The Trust is a subsidiary of the Company, and accordingly is consolidated in the Company's financial statements.
10. 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:
1998 1997 ------------------- (in thousands) Bond improvement fund requirement $ 1,000 $1,750 Less: Portion to be satisfied by certifying property additions 1,000 1,750 --------------------------------------------------------------- Cash sinking fund requirement - - Redemptions of first mortgage bonds - 35,000 Current portion of other long-term debt 50,000 Pollution control bond cash sinking fund requirements 20 20 --------------------------------------------------------------- Total $50,020 $35,020 ===============================================================
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NOTES (continued() Mississippi Power Company 1998 Annual Report
The first mortgage bond improvement fund requirement is one percent of each outstanding series authenticated under the indenture of Mississippi Power 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.
11. COMMON STOCK DIVIDEND RESTRICTIONS
Mississippi Power's first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 1998, 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.
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1998 and 1997 are as follows:
Net Income After Dividends Operating Operating On Preferred Quarter Ended Revenues Income Stock - - - - - - - -------------------------------------------------------------------- (in thousands) March 1998 $122,156 $15,367 $8,388 June 1998 156,612 20,123 13,713 September 1998 191,699 34,167 28,309 December 1998 124,664 10,715 4,696
March 1997 $116,903 $17,132 $10,645 June 1997 128,915 19,340 12,618 September 1997 171,874 30,441 25,163 December 1997 125,896 11,043 5,584 - - - - - - - --------------------------------------------------------------------
Mississippi Power'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
II-187
MANAGEMENT'S REPORT Savannah Electric and Power Company 1998 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 generally accepted accounting principles appropriate in the circumstances 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 books and records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of four 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 generally accepted accounting principles.
/s/ G. Edison Holland, Jr. G. Edison Holland, Jr. President and Chief Executive Officer
/s/ K. R. Willis K. R. Willis Vice-President Treasurer, Chief Financial Officer and Assistant Secretary
February 10, 1999
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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, 1998 and 1997, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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 11-198 through II-210) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Arthur Andersen LLP
Atlanta, Georgia February 10, 1999
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 1998 totaled $23.6 million, representing a $0.2 million decrease from the prior year. This 0.9 percent decline in earnings from 1997 is principally the result of a decrease in other income, net.
In 1997, earnings were $23.8 million, representing a $0.1 million, or 0.4 percent decrease from the prior year. This was principally the result of an increase in other operation expense, partially offset by an increase in other income, net.
Revenues
Total revenues for 1998 were $254.5 million, reflecting a 12.5 percent increase compared to 1997. The following table summarizes the factors affecting operating revenues for the 1996-1998 period: Increase (Decrease) From Prior Year -------------------------------------- 1998 1997 1996 -------------------------------------- Retail -- (in thousands) Sales growth $ (479) $ 7,664 $ 3,679 Weather 8,336 (6,186) (2,813) Fuel cost recovery and other 15,012 (10,002) 12,365 -------------------------------------------------------------------- Total retail 22,869 (8,524) 13,231 -------------------------------------------------------------------- Sales for resale-- Non-affiliates 1,081 1,469 147 Affiliates 964 (1,078) (4,070) -------------------------------------------------------------------- Total sales for resale 2,045 391 (3,923) -------------------------------------------------------------------- Other operating revenues 3,264 336 (963) -------------------------------------------------------------------- Total operating revenues $28,178 $ (7,797) $ 8,345 ==================================================================== Percent change 12.5% (3.3)% 3.7% --------------------------------------------------------------------
Retail revenues increased 10.4 percent in 1998, compared to a decline of 3.7 percent in 1997. The increase in 1998 retail revenues is primarily attributable to the unusually hot summer weather, which led to the increases in the residential and commercial classes. The base rate decrease to the small business customer class, ordered by the Georgia Public Service Commission (GPSC) effective July 1998, more than offset the sales growth in all classes. See Note 3 to the financial statements for additional information. The number of customers was also up in both the residential and commercial categories.
The decline in 1997 retail revenues was attributable to the mild summer weather and a decrease in fuel cost recovery revenues, somewhat offset by customer growth and increased industrial energy sales. Industrial energy sales were higher primarily due to an increase in the demand of a major customer.
Under the Company's fuel cost recovery provisions, fuel revenues--including the fuel component of purchased energy--generally equal fuel expense and have no effect on earnings.
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. Capacity revenues remained unchanged in 1998. The capacity and energy components were as follows:
1998 1997 1996 -------------------------------------- (in thousands) Capacity $ 2 $ 2 $ 2 Energy 401 746 1,329 - - - - - - - ----------------------------------------------------------- Total $403 $748 $1,331 ===========================================================
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 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 1998 and the percent change by year were as follows:
KWH Percent Change ------------ ----------------------------- 1998 1998 1997 1996 ------------ ----------------------------- (in millions) Residential 1,540 7.8% (1.9)% 3.9% Commercial 1,236 6.9 1.3 3.8 Industrial 900 2.1 5.1 (5.5) Other 131 5.3 (1.4) 0.1 ------------ Total retail 3,807 6.0 0.8 1.4 Sales for resale-- Non-affiliates 53 (43.5) 2.9 4.4 Affiliates 59 7.2 30.4 (34.4) ------------ Total 3,919 4.8% 1.2% 0.8% =====================================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1998 Annual Report
Total retail energy sales were up 6.0% in 1998, the strongest showing since 1995. Both residential and commercial energy sales reflected the impact of the hotter-than-normal weather. Industrial energy sales reflected high demand from one industrial customer.
Expenses
Total operating expenses for 1998 were $216.6 million, reflecting a $27.6 million increase from 1997. Major components of this increase include a $17.5 million increase in fuel, a $7.1 million increase in purchased power from non-affiliates, and a $5.5 million increase in maintenance expense. These increases were partially offset by a decrease of $6.4 million in purchased power from affiliates. The increase in fuel expense was primarily attributable to higher demand for energy. The increase in purchased power from non-affiliates primarily resulted from increased power marketing activities. Maintenance expenses were higher primarily due to scheduled turbine dismantle inspection costs. The decline in purchased power from affiliates was due primarily to an increase in internal generation reflecting system load growth.
In 1997, total operating expenses were $189.1 million, reflecting a $6.1 million decrease from 1996. This decrease includes a $16.5 million reduction in purchased power from affiliates, partially offset by increases of $6.4 million in fuel and $3.7 million in other operation expenses. The decrease in purchased power from affiliates was due to an increase in internal generation and to an adjustment in affiliated billings. The increase in fuel expense was primarily attributable to higher generation and to fuel mix. The increase in other operation expense primarily resulted from a one-time charge for work force reductions of $1.9 million, and expenses associated with the implementation of a new computer software system.
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:
1998 1997 1996 -------------------------- Total energy supply (millions of KWHs) 4,182 3,964 3,917 Sources of energy supply (percent) -- Coal 42 34 28 Oil 1 - - Gas 12 5 3 Purchased Power 45 61 69 Total average cost of energy supply (cents) 2.35 2.02 2.30 - - - - - - - -----------------------------------------------------------------
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 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1998 Annual Report
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.
Savannah Electric 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).
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 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 Company is positioning the business to meet the challenge of this major change in the traditional practice of selling electricity. 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 being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers.
Although the Energy Act does not permit retail customer access, it 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 various restructuring and competition initiatives have been or are being discussed in Georgia, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. 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 of the Company. The Company is attempting to minimize or reduce its cost exposure.
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 retail energy sales growth could be limited, and this could significantly erode 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."
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 June 1998, the GPSC issued a four-year accounting order which settled its review of the Company's earnings. See Note 3 to the financial statements for additional information.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1998 Annual Report
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 statement as incurred. At December 31, 1998, 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, 1998, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by the year 2000. This statement establishes accounting and reporting standards for derivative instruments -- including certain derivative instruments embedded in other contracts -- and for hedging activities. The Company has not yet quantified the impact of adopting this statement on its financial statements; however, the adoption could increase volatility in earnings.
In March 1998, the American Institute of Certified Public Accountants (AICPA) issued a new Statement of Position, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement requires capitalization of certain costs of internal-use software. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the Cost of Start-up Activities. This statement requires that the costs of start-up activities and organizational costs be expensed as incurred. Any of these costs previously capitalized by a company must be written off in the year of adoption. The Company adopted this statement in January 1999, and it is not expected to have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The EITF requires that energy trading contracts must be marked to market through the income statement, with gains and losses reflected rather than revenues and purchased power. Energy trading contracts are defined as energy contracts entered into with the objective of generating profits on or from exposure to shifts or changes in market prices. The Company adopted the required accounting in January 1999, and it is not expected to have a material impact on the financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s shortened the year portion of date entries to just two digits. Computers assumed, in effect, that all years began with "19." This practice was widely adopted and hard-coded into computer chips and processors found in some equipment. This approach, intended to save processing time and storage space, was used until the mid-1990s. Unless corrected before the Year 2000, affected software systems and devices containing a chip or microprocessor with date and time functions could incorrectly process dates or the systems may cease to function.
The Company depends on complex computer systems for many aspects of its operations, which include generation, transmission, and distribution of electricity, as well as other business support activities. The Company's goal is to have critical devices or software that are required to maintain operations to be Year 2000 ready by June 1999. Year 2000 ready means that a system or application is determined suitable for continued use through the Year 2000 and beyond. Critical systems include, but are not limited to, safe shutdown systems, turbine generator systems, control center computer systems, customer service systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000 challenge and has dedicated what it believes to be adequate resources to address the issue. The Millennium Project is a team of employees, IBM consultants, and other contractors whose progress is reviewed on a monthly basis by a steering committee of Southern Company executives.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1998 Annual Report
The Company's Year 2000 program was divided into two phases. Phase I began in 1996 and consisted of identifying and assessing corporate assets related to software systems and devices that contain a computer chip or clock. The first phase was completed in June 1997. Phase 2 consists of testing and remediating high priority systems and devices. Also, contingency planning is included in this phase. Completion of Phase 2 is targeted for June 1999. The Millennium Project will continue to monitor the affected computer systems, devices, and applications into the Year 2000.
Southern Company has completed more than 70 percent of the activities contained in its work plan. The percentage of completion and projected completion by function are as follows:
- - - - - - - ------------------------------------------------------------------------- Work Plan ------------------------------------------------ Remediation Project Inventory Assessment Testing Completion - - - - - - - ------------------------------------------------------------------------- Generation 100% 100% 70% 6/99 - - - - - - - ------------------------------------------------------------------------- Energy Management 100 100 90 6/99 - - - - - - - ------------------------------------------------------------------------- Transmission and Distribution 100 100 100 1/99 - - - - - - - ------------------------------------------------------------------------- Telecommunications 100 100 50 6/99 - - - - - - - ------------------------------------------------------------------------- Corporate Applications 100 100 90 3/99 - - - - - - - ------------------------------------------------------------------------
Year 2000 Costs
Current projected total costs for Southern Company for Year 2000 readiness are approximately $91 million, which includes $6 million of cost billed to non-affiliated companies. These costs include labor necessary to identify, test, and remediate affected devices and systems. From its inception through December 31, 1998, the Year 2000 program costs for Southern Company, recognized as expense, amounted to $56 million. The Company's total estimated costs related to the project are approximately $1.2 million. Year 2000 costs of $0.5 million and $0.2 million were expensed in 1998 and 1997, respectively. The Company's estimated cost of completion is $0.5 million.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of service interruptions related to the Year 2000. The Company believes, based on current tests, that the system can provide customers with electricity. These tests increase confidence, but do not guarantee error-free operations. The Company is taking what it believes to be prudent steps to prepare for the Year 2000, and it expects any interruptions in service that may occur within the service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe than the scenarios that its electric system is routinely prepared to handle. The most likely worst case scenario consists of the service loss of one of the largest generating units and/or the service loss of any single bulk transmission element in its service territory. The Company has followed a proven methodology for identifying and assessing software and devices containing potential Year 2000 challenges. Remediation and testing of those devices are in progress. Following risk assessment, the Company is preparing contingency plans as appropriate and is participating in North American Electric Reliability Council-coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third parties that provide goods and services crucial to the Company's operations. Among such critical third parties are fuel, transportation, telecommunications, water, chemical, and other suppliers. Contingency plans based on the assessment of each third party's ability to continue supplying critical goods and services to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical demand by customers because of their own Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled at developing and using contingency plans in unusual circumstances. As part of Year 2000 business continuity and contingency planning, the Company is drawing on that experience to make risk assessments and developing additional plans to deal specifically with situations that could arise relative to Year 2000 challenges. The Company is identifying critical operational locations, and key employees will be on duty at those locations during the Year 2000 transition. In September 1999, drills are scheduled to be conducted to test contingency plans. Because of the level of detail of the contingency planning process, management feels that the contingency plans will keep any service interruptions that may occur within the service territory isolated and short in duration.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1998 Annual Report
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1998 was the addition of $18.1 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.
Capital Structure
As of December 31, 1998, the Company's capital structure consisted of 46.4 percent common stock equity, 10.5 percent trust preferred securities, and 43.1 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 equity at 48 percent, preferred securities at 10 percent and debt at 42 percent.
In March 1998, the Company issued $30 million of Series A 6 5/8% senior retail intermediate bonds maturing in 2015. The Company used these proceeds to redeem the remaining amount of its 8.30% first mortgage bonds due in 2022. Maturities and retirements of long-term debt were $30 million in 1998, $14 million in 1997, and $29 million in 1996.
In November 1998, the Company redeemed all of its 1,400,000 shares of 6.64% Series Preferred Stock at a redemption price of $25 per share, plus accrued dividends through the date of redemption.
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.
The composite interest rates and dividend rates for the years 1996 through 1998 as of year-end were as follows:
1998 1997 1996 ------------------------------- Composite interest rates on long-term debt 6.5% 6.9% 7.0% Preferred stock dividend rate -% 6.6% 6.6% Trust preferred securities dividend rate 6.9% -% -% ==================================================================
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $92 million ($29 million in 1999, $32 million in 2000, and $31 million in 2001). 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. In early 1999, the Company will issue a Request for Proposal for bids to provide its capacity requirements for 2002. These bids will be compared to self-build options to identify the least cost supply option. The supply decision should be made by late summer. Construction of transmission and distribution facilities and upgrading of generating plants will be continuing.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $31.9 million will be needed by the end of 2001 for maturities of long-term debt and present sinking fund requirements.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1998 Annual Report
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act--the acid rain compliance provision of the law--significantly affected the Company and other subsidiaries of Southern 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 initially affected 28 generating units of Southern Company. As a result of Southern Company's compliance strategy, an additional 22 generating units, which included four of the Company's units, were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. This compliance strategy resulted in unused emission allowances being banked for later use. Construction expenditures for Phase I compliance totaled approximately $2 million for Savannah Electric.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as necessary to meet Phase II limits. Current compliance strategy for Phase II and ozone non-attainment could require total estimated construction expenditures for Southern Company of approximately $70 million, of which $16 million remains to be spent. Phase II compliance is not expected to have a material impact on Savannah Electric.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. In September 1998, the EPA issued the final regional nitrogen oxide rules to the states for implementation. The states have one year to adopt and implement the rules. The final rules affect 22 states including Georgia. The EPA rules are being challenged in the courts by several states and industry groups. Implementation of the final state rules could require substantial further reductions in nitrogen oxide emissions from fossil-fired generating facilities and other industry in these states. Implementation of the standards could result in significant additional compliance costs and capital expenditures that cannot be determined until the results of legal challenges are known, and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: nitrogen oxide emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; control strategies to reduce regional haze; and hazardous waste disposal requirements. The impact of 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 currently or previously owned. The Company conducts studies to determine the extent of any required cleanup costs and will recognize in the financial statements any 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 Southern Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect Southern Company. The impact of new legislation--if any--will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1998 Annual Report
Sources of Capital
At December 31, 1998, the Company had $6.0 million of cash and $40.5 million of unused short-term credit arrangements with banks to meet its short-term cash needs. Revolving credit arrangements of $20 million, which expire December 31, 2001, are also used to meet short-term cash needs and to provide additional interim funding for the Company's construction program. Of the revolving credit arrangements, $20 million remained unused at December 31, 1998.
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. In December 1998, the Company obtained stockholder approval to amend the corporate charter including the elimination of the 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
Savannah Electric and Power Company's 1998 Annual Report contains forward-looking and historical information. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking information; accordingly, there can be no assurance that such indicated results will be realized. These factors include legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry; 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 internal restructuring--that may be pursued by the Company; state and federal rate regulation; Year 2000 issues; changes in or application of environmental and other laws and regulations to which the Company is subject; political, legal and economic conditions and developments; financial market conditions and the results of financing efforts; changes in commodity prices and interest rates; weather and other natural phenomena; and other factors discussed in the reports--including Form 10-K--filed from time to time by the Company with the Securities and Exchange Commission.
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STATEMENTS OF INCOME For the Years Ended December 31, 1998, 1997, and 1996 Savannah Electric and Power Company 1998 Annual Report
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1998, 1997, and 1996 Savannah Electric and Power Company 1998 Annual Report
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BALANCE SHEETS At December 31, 1998 and 1997 Savannah Electric and Power Company 1998 Annual Report
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BALANCE SHEETS At December 31, 1998 and 1997 Savannah Electric and Power Company 1998 Annual Report
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STATEMENTS OF CAPITALIZATION At December 31, 1998 and 1997 Savannah Electric and Power Company 1998 Annual Report
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NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Savannah Electric and Power Company (the Company), is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern LINC), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The operating companies provide electric service in four southeastern states. Contracts among the companies--dealing with jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Company Energy Solutions develops new business opportunities related to energy products and services.
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 generally accepted accounting principles and complies with the accounting policies and practices prescribed by the GPSC. The preparation of financial statements in conformity with generally accepted accounting principles 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.
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:
1998 1997 --------------------------- (in thousands) Deferred income taxes $ 17,130 $ 17,267 Premium on reacquired debt 8,570 7,121 Deferred income tax credits (21,349) (21,469) Storm damage reserves (1,580) (1,500) Accelerated depreciation (1,000) - - - - - - - - --------------------------------------------------------------- Total $ 1,771 $ 1,419 ===============================================================
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 net regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia, and to non-affiliated customers in the Southeast. Revenues, less affiliated transactions, by type of service were as follows:
1998 1997 1996 -------------------------------------- (in thousands) Retail $242,327 $219,458 $227,982 Sales for resale-- Non-affiliates 4,548 3,467 1,998 Other 4,564 1,300 964 - - - - - - - ------------------------------------------------------------ Total $251,439 $224,225 $230,944 ============================================================
Other revenues include rents and revenues from non-utility services.
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NOTES (continued) Savannah Electric and Power Company 1998 Annual Report
The Company accrues revenues for service rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The Company's electric rates 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 rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1998, uncollectible accounts continued to average less than 1 percent of revenues.
In January 1999, the GPSC approved an increase of slightly over one-tenth of a cent per kilowatt-hour in the Company's fuel allowance, effective in February 1999.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 1998 and 1997 and 2.8 percent in 1996. 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. 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 8.00 percent in 1998, 9.24 percent in 1997 and 8.69 percent in 1996.
Utility Plant
Utility plant is stated at original cost, which includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and AFUDC. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
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'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, 1998 $158 $162 At December 31, 1997 158 161 Trust preferred securities: At December 31, 1998 $40 $40 At December 31, 1997 - -
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) Savannah Electric and Power Company 1998 Annual Report
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.
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 deductible under federal income tax regulations or to the extent required by the GPSC. In 1998, the Company adopted FASB Statement No. 132, Employers' Disclosure about Pensions and Other Postretirement Benefits. The measurement date is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefit plans were:
1998 1997 - - - - - - - --------------------------------------------------------------- Discount 6.75% 7.50% Annual salary increase 4.25 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 --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $51,720 $49,914 Service cost 1,495 1,393 Interest cost 3,806 3,556 Benefits paid (3,392) (2,403) Actuarial (gain) loss and employee transfers 4,343 (740) Amendments 1,235 - - - - - - - - --------------------------------------------------------------- Balance at end of year $59,207 $51,720 ===============================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $50,630 $42,430 Actual return on plan assets 171 7,603 Employer contributions 2,464 3,000 Benefits paid (3,392) (2,403) Employee transfers (243) - - - - - - - - --------------------------------------------------------------- Balance at end of year $49,630 $50,630 ===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1998 1997 - - - - - - - ----------------------------------------------------------------- (in thousands) Funded status $(9,577) $(1,090) Unrecognized transition obligation 266 355 Unrecognized prior service cost 2,874 1,884 Unrecognized net loss 9,718 1,275 Fourth quarter contributions - 1,000 - - - - - - - ----------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 3,281 $ 3,424 =================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - ----------------------------------------------------------------- (in thousands) Service cost $1,495 $1,393 $1,352 Interest cost 3,806 3,556 3,389 Expected return on plan assets (3,992) (3,782) (3,263) Recognized net loss 2 475 626 Net amortization 334 280 224 - - - - - - - ----------------------------------------------------------------- Net pension cost $1,645 $1,922 $2,328 =================================================================
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NOTES (continued) Savannah Electric and Power Company 1998 Annual Report
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $20,899 $20,520 Service cost 348 319 Interest cost 1,527 1,499 Benefits paid (839) (526) Actuarial (gain) loss and employee transfers 1,621 (913) - - - - - - - --------------------------------------------------------------- Balance at end of year $23,556 $20,899 ===============================================================
Plan Assets --------------------------- 1998 1997 - - - - - - - --------------------------------------------------------------- (in thousands) Balance at beginning of year $3,110 $2,473 Actual return on plan assets 85 365 Employer contributions 1,447 798 Benefits paid (839) (526) - - - - - - - --------------------------------------------------------------- Balance at end of year $3,803 $3,110 ===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows: 1998 1997 - - - - - - - ----------------------------------------------------------------- (in thousands) Funded status $(19,753) $(17,789) Unrecognized transition obligation 6,913 7,407 Unrecognized net loss 5,444 3,737 Fourth quarter contributions 1,152 749 - - - - - - - ----------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (6,244) $(5,896) =================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996 - - - - - - - ---------------------------------------------------------------- (in thousands) Service cost $ 348 $ 319 $ 360 Interest cost 1,528 1,499 1,422 Expected return on plan assets (276) (211) (129) Recognized net loss 104 125 171 Net amortization 494 494 494 - - - - - - - ----------------------------------------------------------------- Net postretirement cost $2,198 $2,226 $2,318 ================================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.30 percent for 1998, decreasing gradually to 4.75 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, 1998 as follows:
1 Percent 1 Percent Increase Decrease - - - - - - - --------------------------------------------------------------- (in thousands) Benefit obligation $1,301 $(1,227) Service and interest costs 107 (101) ===============================================================
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. Benefit costs associated with this plan were $0.4 million for 1998, 1997 and 1996.
Work Force Reduction Program
In 1997, the Company incurred a $1.9 million, one-time charge to other operation expense for costs related to the implementation of a work force reduction program.
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NOTES (continued) Savannah Electric and Power Company 1998 Annual Report
3. 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 June 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 the next four years. The Company will also expense an additional $1.95 million in storm damage accruals and accrue an additional $8 million in depreciation on generating assets over the term of the order. The additional depreciation will be accumulated in a regulatory liability account to be available to mitigate any potential stranded costs. In addition, the Company has discretionary authority to provide up to an additional $0.3 million per year in storm damage accruals and up to an additional $4.0 million in depreciation expense over the four years. The Company is also precluded from asking for a rate increase except upon significant changes in economic conditions, new laws, or regulations. There will be a quarterly monitoring of the Company's earnings performance.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently estimated to total $29 million in 1999, $32 million in 2000, and $31 million in 2001. 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 transmission and distribution facilities and the upgrading of generating plants will continue.
5. FINANCING AND COMMITMENTS
General
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, preferred securities, and capital contributions from Southern Company.
The amounts of long-term debt and 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 1998, unused credit arrangements with six banks totaled $40.5 million and expire at various times during 1999 and 2000.
The Company's revolving credit arrangements of $20 million, all of which remained unused as of December 31, 1998, expire December 31, 2001. These agreements allow short-term borrowings to be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at the Company's option.
In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments.
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.
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NOTES (continued) Savannah Electric and Power Company 1998 Annual Report
Fuel 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 $12.0 million and $9.0 million for 1999 and 2000, respectively.
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $1.1 million for 1998, $1.2 million for 1997, and $1.6 million for 1996. The Company entered into a 22.5 year lease agreement effective December 1, 1995 for 100 new aluminum rail cars at an annual cost of approximately $0.5 million. The rail cars are used to transport coal to one of the Company's generating plants.
At December 31, 1998, estimated future minimum lease payments for noncancelable operating leases were as follows:
Rental Commitments -------------------- (in thousands) 1999 $ 483 2000 483 2001 483 2002 483 2003 483 2004 and thereafter 6,969 - - - - - - - -------------------------------------------------------------
6. INCOME TAXES
At December 31, 1998, tax-related regulatory assets and liabilities were $17 million and $21 million, respectively. The assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. 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:
1998 1997 1996 -------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $ 6,763 $ 9,743 $ 7,084 Deferred -- current year 8,377 4,522 8,216 -- reversal of prior years (2,565) (1,381) (1,989) - - - - - - - ------------------------------------------------------------------ 12,575 12,884 13,311 - - - - - - - ------------------------------------------------------------------ State -- Currently payable 1,327 1,603 575 Deferred -- current year 1,174 569 1,216 -- reversal of prior years 25 130 39 - - - - - - - ------------------------------------------------------------------ 2,526 2,302 1,830 - - - - - - - ------------------------------------------------------------------ Total 15,101 15,186 15,141 Less income taxes credited to other income (1,234) (1,233) (1,034) - - - - - - - ------------------------------------------------------------------ Total income taxes charged to operations $16,335 $16,419 $16,175 ==================================================================
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:
1998 1997 -------------------- Deferred tax liabilities: (in thousands) Accelerated depreciation $75,187 $72,663 Property basis differences 7,591 8,034 Other 10,187 5,850 - - - - - - - ---------------------------------------------------------------- Total 92,965 86,547 - - - - - - - ---------------------------------------------------------------- Deferred tax assets: Pension and other benefits 4,892 5,338 Other 2,828 2,957 - - - - - - - ---------------------------------------------------------------- Total 7,720 8,295 - - - - - - - ---------------------------------------------------------------- Net deferred tax liabilities 85,245 78,252 Portions included in current assets, net (2,467) 2,445 - - - - - - - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $82,778 $80,697 ================================================================
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 $0.7 million in 1998, 1997, and 1996. At December 31, 1998, all investment tax credits available to reduce federal income taxes payable had been utilized.
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NOTES (continued) Savannah Electric and Power Company 1998 Annual Report
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
1998 1997 1996 --------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of federal income tax benefit 4 4 3 Other (2) (2) (1) -------------------------------------------------------------- Effective income tax rate 37% 37% 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. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
7. CUMULATIVE PREFERRED STOCK AND TRUST PREFERRED SECURITIES
In November 1998, the Company redeemed all of its 1,400,000 shares of 6.64% Series Preferred Stock at a redemption price of $25 per share, plus accrued dividends through the date of redemption.
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 Trust I 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 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.
8. 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.
In March 1998, the Company issued $30 million of Series A 6 5/8% senior retail intermediate bonds maturing in 2015. The Company used these proceeds to redeem the remaining amount of its 8.30% first mortgage bonds due in 2022. Maturities and retirements of long-term debt were $30 million in 1998, $14 million in 1997 and $29 million in 1996.
In April 1997, the Company issued $14 million in variable rate pollution control obligations (bank note) maturing in 2037. The Company redeemed all of its remaining outstanding 6 3/4% Pollution Control Bonds due 2022.
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:
1998 1997 --------------------- (in thousands) Bond sinking fund requirement $800 $ 1,100 Less: Portion to be satisfied by certifying property additions 800 - - - - - - - - ------------------------------------------------------------------- Cash sinking fund requirement - 1,100 Other long-term debt maturities 689 20,664 - - - - - - - ------------------------------------------------------------------- Total $689 $21,764 ===================================================================
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NOTES (continued) Savannah Electric and Power Company 1998 Annual Report
The first mortgage bond improvement (sinking) fund requirements amount to 1 percent of each outstanding series of bonds authenticated under the Indenture prior to January 1 of each year, other than those issued to collateralize pollution control and other obligations. The requirements may be satisfied by depositing cash or reacquiring bonds, or by pledging additional property equal to 1 2/3 times the requirements.
The sinking fund requirements of first mortgage bonds were satisfied by cash redemption in 1998 and by certifying property additions in 1997. It is anticipated that the 1999 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2003 applicable to long-term debt are as follows: $0.7 million in 1999; $0.6 million in 2000; $30.5 million in 2001; $0.5 million in 2002; and $20.4 million in 2003.
9. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Indenture contains certain limitations on the payment of cash dividends on common stock. At December 31, 1998, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Indenture.
10. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1998 and 1997 are as follows (in thousands):
Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock - - - - - - - ------------------------------------------------------------------
March 1998 $48,381 $ 6,214 $ 2,426 June 1998 69,616 11,606 7,807 September 1998 84,224 16,056 12,518 December 1998 52,234 3,936 893
March 1997 $42,945 $ 6,117 $ 2,545 June 1997 52,516 8,626 5,136 September 1997 79,900 17,531 14,276 December 1997 50,916 4,950 1,890 - - - - - - - ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
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SELECTED FINANCIAL AND OPERATING DATA Savannah Electric and Power Company 1998 Annual Report
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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 1999 annual meeting of stockholders. The ages of directors and executive officers in Item 10 set forth below are as of December 31, 1998.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
ALABAMA
Identification of directors of ALABAMA.
Elmer B. Harris (1) President and Chief Executive Officer Age 59 Served as Director since 3-1-89
Whit Armstrong (2) Age 51 Served as Director since 9-24-82
David J. Cooper, Sr. (2) Age 53 Served as Director since 4-24-98
A. W. Dahlberg (2) Age 58 Served as Director since 4-22-94
Peter V. Gregerson, Sr. (2) Age 70 Served as Director since 10-22-93
Carl E. Jones, Jr. (2) Age 58 Served as Director since 4-22-88
Patricia M. King (2) Age 53 Served as Director since 7-25-97
James K. Lowder (2) Age 49 Served as Director since 7-25-97
Wallace D. Malone, Jr. (2) Age 62 Served as Director since 6-22-90
Thomas C. Meredith (2) Age 57 Served as Director since 10-23-98
William V. Muse (2) Age 59 Served as Director since 2-26-93
John T. Porter (2) Age 67 Served as Director since 10-22-93
Robert D. Powers (2) Age 48 Served as Director since 1-24-92
Andreas Renschler (2) Age 40 Served as Director since 1-23-98
C. Dowd Ritter (2) Age 51 Served as Director since 7-25-97
William J. Rushton, III (2) Age 69 Served as Director since 9-18-70
James H. Sanford (2) Age 54 Served as Director since 8-1-83
John C. Webb, IV (2) Age 56 Served as Director since 4-22-77
(1) Previously served as Director of ALABAMA from 1980 to 1985. (2) No position other than Director.
Each of the above is currently a director of ALABAMA, serving a term running from the last annual meeting of ALABAMA's stockholder (April 24, 1998) for one year until the next annual meeting or until a successor is elected and qualified, except for Dr. Meredith, who was elected on the date indicated.
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There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of ALABAMA acting solely in their capacities as such.
Identification of executive officers of ALABAMA.
Elmer B. Harris (1) President, Chief Executive Officer and Director Age 59 Served as Executive Officer since 3-1-89
Banks H. Farris Executive Vice President Age 63 Served as Executive Officer since 12-3-91
Michael D. Garrett Executive Vice President - External Affairs Age 49 Served as Executive Officer since 3-1-98
William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer Age 55 Served as Executive Officer since 12-3-91
Earl B. Parsons, Jr. Senior Vice President Age 60 Served as Executive Officer since 6-1-98
(1) Previously served as executive officer of ALABAMA from 1979 to 1985.
Each of the above is currently an executive officer of ALABAMA, serving a term running from the last annual meeting of the directors (April 24, 1998) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Parsons, who was elected on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of ALABAMA acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
Elmer B. Harris - President and Chief Executive Officer since 1989. Director of SOUTHERN and AmSouth Bancorporation.
Whit Armstrong - President, Chairman of the Board and Director of The Citizens Bank, Enterprise, Alabama. Also, President, Chairman of the Board and Director of Enterprise Capital Corporation, Inc. Director of The Enstar Group, Inc.
David J. Cooper, Sr. - President of Cooper/T. Smith Corporation, a maritime company with a core business of stevedoring and tugboats. Director of Cooper/T. Smith Corporation and subsidiaries. Chairman of the Board, American Equity Underwriters, Inc., Mobile, Alabama.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of SOUTHERN since 1995. He previously served as President of SOUTHERN from 1994 to 1995 and President and Chief Executive Officer of GEORGIA from 1988 through 1993. Director of SOUTHERN, GEORGIA, Equifax, Inc., Protective Life Corporation and SunTrust Banks, Inc.
Peter V. Gregerson, Sr. - Chairman Emeritus of Gregerson's Foods, Inc. (retail groceries), Gadsden, Alabama.
Carl E. Jones, Jr. - President and Chief Executive Officer of Regions Financial Corporation, Birmingham, Alabama.
Patricia M. King - President and Chief Executive Officer of King Motor Co., Inc., King's Highway, Inc. and King Imports, Inc., Anniston, Alabama. Director of Regions Bank, Anniston, Alabama.
James K. Lowder - President and Chief Executive Officer of The Colonial Company (real estate development and sales), Montgomery, Alabama.
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Wallace D. Malone, Jr. - Chairman and Chief Executive Officer of SouthTrust Corporation, bank holding company, Birmingham, Alabama. Director of American Cast Iron Pipe Company, Birmingham, Alabama.
Thomas C. Meredith - Chancellor of The University of Alabama System, Tuscaloosa, Alabama. Director of ATMOS Energy Corporation, Dallas, Texas.
William V. Muse - President of Auburn University, Auburn, Alabama. Director of SouthTrust Bank and American Cast Iron Pipe Company, Birmingham, Alabama.
John T. Porter - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama. Director of Citizens Federal Savings Bank, Birmingham, Alabama.
Robert D. Powers - President and Director, The Eufaula Agency, Inc. (real estate and insurance), Eufaula, Alabama.
Andreas Renschler - President and Chief Executive Officer of Mercedes-Benz U.S. International, Inc., Tuscaloosa County, Alabama.
C. Dowd Ritter - Chairman, President, Chief Executive Officer and Director, AmSouth Bancorporation and AmSouth Bank, Birmingham, Alabama.
William J. Rushton, III - Chairman Emeritus of Protective Life Corporation (insurance holding company), Birmingham, Alabama. Director of SOUTHERN.
James H. Sanford - Chairman, HOME Place Farms Inc. (diversified farmers and ginners), Prattville, Alabama. President, Autauga Quality Cotton Association. Chairman of the Board, Sylvest Farms of Georgia, Inc., College Park, Georgia. Chairman of the Board, Sylvest Poultry Inc., Montgomery, Alabama.
John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber and wood products sales), Demopolis, Alabama. Director of J. F. Suttle, Co.
Banks H. Farris - Executive Vice President - Customer Service since 1994. Responsible for providing the overall management of human resources, information resources, power delivery and marketing departments, customer service centers and the six geographic divisions. He previously served as Senior Vice President from 1991 to 1994.
Michael D. Garrett - Executive Vice President - External Affairs since 1998. Responsible for governmental relations, environmental, public relations, economic development, corporate real estate and corporate services. He previously served as Senior Vice President - External Affairs from February 1994 to March 1998. Director of AmSouth Bank, Birmingham, Alabama.
William B. Hutchins, III - Executive Vice President, and Chief Financial Officer since 1991. Treasurer was added to his responsibilities in 1998. Responsible for financial and accounting operations, corporate planning and treasury operations. He previously served as Senior Vice President and Chief Financial Officer from 1991 to 1994.
Earl B. Parsons, Jr. - Senior Vice president - Fossil and Hydro Generation since 1995. Responsible for providing the overall management of the Fossil Generation, Hydro Generation, Power Generation Support and Fuels Department. He previously served as Vice President of Power Generation and Transmission at GULF.
Involvement in certain legal proceedings. None.
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GEORGIA
Identification of directors of GEORGIA.
H. Allen Franklin President and Chief Executive Officer Age 54 Served as Director since 1-1-94
Warren Y. Jobe Executive Vice President Age 58 Served as Director since 8-1-82
Daniel P. Amos (1) Age 47 Served as Director since 5-21-97
Juanita P. Baranco (1) Age 49 Served as Director since 5-21-97
A. W. Dahlberg (1) Age 58 Served as Director since 6-1-88
William A. Fickling, Jr. (1) Age 66 Served as Director since 4-18-73
L. G. Hardman III (1) Age 59 Served as Director since 6-25-79
James R. Lientz, Jr. (1) Age 55 Served as Director since 7-21-93
Zell Miller (1) Age 67 Served as Director since 2-17-99
G. Joseph Prendergast (1) Age 53 Served as Director since 1-20-93
Herman J. Russell (1) Age 68 Served as Director since 5-18-88
Gloria M. Shatto (1) Age 67 Served as Director since 2-20-80
William Jerry Vereen (1) Age 58 Served as Director since 5-18-88
Carl Ware (1) (2) Age 55 Served as Director since 2-15-95
(1) No position other than Director. (2) Previously served as Director of GEORGIA from 1980 to 1991.
Each of the above is currently a director of GEORGIA, serving a term running from the last annual meeting of GEORGIA's stockholder (May 20, 1998) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Miller, who was elected on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he/she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GEORGIA acting solely in their capacities as such.
Identification of executive officers of GEORGIA.
H. Allen Franklin President, Chief Executive Officer and Director Age 54 Served as Executive Officer since 1-1-94
Warren Y. Jobe Executive Vice President and Director Age 58 Served as Executive Officer since 5-19-82
William C. Archer, III Executive Vice President - External Affairs Age 50 Served as Executive Officer since 4-6-95
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Gene R. Hodges Executive Vice President - Customer Operations Age 60 Served as Executive Officer since 11-19-86
David M. Ratcliffe Executive Vice President, Treasurer and Chief Financial Officer Age 50 Served as Executive Officer since 3-1-98
Wayne T. Dahlke Senior Vice President - Power Delivery Age 57 Served as Executive Officer since 4-19-89
James K. Davis Senior Vice President - Corporate Relations Age 58 Served as Executive Officer since 10-1-93
Robert H. Haubein Senior Vice President - Fossil/Hydro Power Age 58 Served as Executive Officer since 2-19-92
Leonard J. Haynes Senior Vice President - Marketing Age 48 Served as Executive Office since 10-13-98
Fred R. Williams Senior Vice President - Resource Policy & Planning Age 54 Served as Executive Officer since 11-18-92
Each of the above is currently an executive officer of GEORGIA, serving a term running from the last annual meeting of the directors (May 20, 1998) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Haynes, who was elected on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of GEORGIA acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
H. Allen Franklin - President and Chief Executive Officer since 1994. He previously served as President and Chief Executive Officer of SCS from 1988 through 1993. Director of SOUTHERN and SouthTrust Corporation.
Warren Y. Jobe - Executive Vice President since 1982. He previously served as Chief Financial Officer and Treasurer from 1982 to 1998. Effective February 1998, elected Senior Vice President of SOUTHERN with responsibilities for corporate development, including customer relations and civic and community affairs.
Daniel P. Amos - President and Chief Executive Officer, American Family Life Assurance Company, Incorporated (AFLAC), Columbus, Georgia. Director, AFLAC Incorporated (and subsidiaries), CIT Group and Greystone Capital Partners, I.L.P.
Juanita P. Baranco - Business owner of Baranco Automotive Group. Director of Federal Reserve Bank of Atlanta and John H. Harland Company, Decatur, Georgia.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of SOUTHERN since 1995. He previously served as President of SOUTHERN from 1994 to 1995 and President and Chief Executive Officer of GEORGIA from 1988 through 1993. Director of SOUTHERN, ALABAMA, Equifax, Inc., Protective Life Corporation and SunTrust Banks, Inc.
William A. Fickling, Jr. - Chairman of the Board, Chief Executive Officer of Beech Street Corporation (provider of managed care services) and President from 1995 to 1996. He previously served as Chairman of the Board and Chief Executive Officer of Charter Medical Corporation (provider of psychiatric care).
L. G. Hardman III - Chairman of the Board and Chief Executive Officer of First Commerce Bancorp, Inc. Chairman of the Board of The First National Bank of Commerce, Georgia and Chairman of the Board, President and Treasurer of Harmony Grove Mills, Inc. (real estate investments). Director of SOUTHERN.
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James R. Lientz, Jr. - President, NationsBank, Mid-South Banking Group since 1993. He previously served as President and Chief Executive Officer of former C&S of South Carolina (now NationsBank) from 1990 to 1993. Director of Cerulean Companies, Inc. and Blue Cross/Blue Shield of Georgia.
Zell Miller - Former Governor of Georgia. He served two terms as Governor of the State of Georgia, leaving office in January 1999. He previously served as Lieutenant Governor of Georgia. Director of Albany-based Gray Communications, Atlanta-based Post Properties, Atlanta-based Law Companies Group and United Community Banks, Inc., Blairsville, GA.
G. Joseph Prendergast - Senior Executive Vice President, Wachovia Corporation. Heads the banking division comprising the companies' consumer and corporate banking activities and Wachovia Bank, N.A.
Herman J. Russell - Chairman and Chief Executive Officer of H. J. Russell & Company (construction), Atlanta, Georgia. Chairman of the Board, Citizens Trust Bank, Atlanta, Georgia. Director of Wachovia Corporation and First Union Real Estate and Mortgage Investments.
Gloria M. Shatto - President Emerita, Berry College, Mount Berry, Georgia. Director of SOUTHERN, Becton Dickinson & Company and Texas Instruments Incorporated.
William Jerry Vereen - President, Treasurer and Chief Executive Officer of Riverside Manufacturing Company (manufacture and sale of uniforms), Moultrie, Georgia. Director of Gerber Scientific, Inc., Textile Clothing Technology Corporation, Cerulean Companies, Inc. and Blue Cross/Blue Shield of Georgia.
Carl Ware - President, Africa Group, The Coca-Cola Company since 1991.
William C. Archer, III - Executive Vice President - External Affairs since September 1995. Senior Vice President - External Affairs from April 1995 to September 1995. Vice President - Human Resources for SCS from 1992 to 1995. Responsible for governmental and regulatory affairs, corporate relations, land department, environmental affairs, corporate communications, risk management, corporate security, regulatory and litigation support and corporate concerns. Gene R. Hodges - Executive Vice President - Customer Operations, Power Delivery and Safety since 2-19-92. Elected Vice President in charge of customer service and power delivery in 1992. Safety department was added to the Executive Vice President's responsibilities in 1995. Responsible for the northern and southern regions and power delivery, customer service, region safety and labor relations areas.
David M. Ratcliffe - Executive Vice President and Treasurer since 3-1-98 and Executive Vice President, Treasurer and Chief Financial Officer since 5-20-98. He previously served as Senior Vice President - External Affairs of SOUTHERN from 1995 to 1998. President and Chief Executive Officer of MISSISSIPPI from 1991 to 1995. Responsible for accounting, corporate secretary, finance and procurement.
Wayne T. Dahlke - Senior Vice President - Power Delivery since 1992. Senior Vice President - Marketing from 1989 to 1992. Responsible for transmission and construction, planning and projects, distribution, forestry and right of way services and system operations.
James K. Davis - Senior Vice President - Corporate Relations since 1993. Vice President of Corporate Relations from 1988 to 1993. Responsible for corporate relations and consumer affairs.
Robert H. Haubein - Senior Vice President - Fossil/ Hydro Power since 1994. Senior Vice President - Administrative Services from 1992 to 1994. Responsible for fossil/hydro power generation, labor relations, safety and health.
Leonard J. Haynes - Senior Vice President - Marketing since 1998. Vice President of Marketing from October 1995 to November 1998. Responsible for GEORGIA's and SAVANNAH's Power Marketing organizations as well as SOUTHERN's national accounts organization.
Fred R. Williams - Senior Vice President - Resource Policy and Planning since 1997. Senior Vice President - Wholesale Power Marketing from 1995 to 1997. Senior Vice President - Bulk Power Markets from 1992 to August 1995. Responsible for managing the supply needs for retail and wholesale customers and developing policy and recommendations for future industry structure.
Involvement in certain legal proceedings. None.
III-6
GULF
Identification of directors of GULF.
Travis J. Bowden President and Chief Executive Officer Age 60 Served as Director since 2-1-94
Paul J. DeNicola (1) Age 50 Served as Director since 4-19-91
Fred C. Donovan, Sr. (1) Age 58 Served as Director since 1-18-91
W. Deck Hull, Jr. (1) Age 66 Served as Director since 10-14-83
Joseph K. Tannehill (1) Age 65 Served as Director since 7-19-85
Barbara H. Thames (1) Age 58 Served as Director since 2-28-97
(1) No position other than Director.
Each of the above is currently a director of GULF, serving a term running from the last annual meeting of GULF's stockholder (June 30, 1998) 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 was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GULF acting solely in their capacities as such.
Identification of executive officers of GULF.
Travis J. Bowden President, Chief Executive Officer and Director Age 60 Served as Executive Officer since 2-1-94
Francis M. Fisher, Jr. Vice President - Power Delivery and Customer Operations Age 50 Served as Executive Officer since 5-19-89
John E. Hodges, Jr. Vice President - Marketing and Employee/External Affairs Age 55 Served as Executive Officer since 5-19-89
Robert G. Moore Vice President - Power Generation and Transmission Age 49 Served as Executive Officer since 7-25-97
Arlan E. Scarbrough Vice President - Finance Age 62 Served as Executive Officer since 9-21-77
Each of the above is currently an executive officer of GULF, serving a term running from the last annual meeting of the directors (July 24, 1998) for one year until the next annual meeting or until his 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 was or is to be selected as an officer, other than any arrangements or understandings with officers of GULF acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
Travis J. Bowden - President and Chief Executive Officer since 1994. He previously served as Executive Vice President of ALABAMA from 1985 to 1994.
III-7
Paul J. DeNicola - President and Chief Executive Officer of SCS since 1994. Executive Vice President and Group Executive of SOUTHERN since 1991. He previously served as Executive Vice President of SCS from 1991 through 1993. Director of SOUTHERN, MISSISSIPPI and SAVANNAH.
Fred C. Donovan, Sr. - President of Baskerville - Donovan, Inc., an architectural and engineering firm, Pensacola, Florida.
W. Deck Hull, Jr. - President and Director of Hull Company - Panama City, Florida. He previously served as Vice Chairman of the SunTrust Bank, West Florida, Panama City, Florida.
Joseph K. Tannehill - President, Chairman and Chief Executive Officer of Tannehill International Industries, Inc., Lynn Haven, Florida. Director of Regions Bank of North Florida, Panama City, Florida.
Barbara H. Thames - Vice President of West Florida Regional Medical Center, Pensacola, Florida. She previously served as Chief Executive Officer of Santa Rosa Medical Center, Milton, Florida.
Francis M. Fisher, Jr. - Vice President - Power Delivery and Customer Operations since 1996. He previously served as Vice President-Employee and External Relations from 1989 to 1996. Responsible for power delivery, customer operations, corporate real estate, and total quality management and serves as compliance officer.
John E. Hodges, Jr. - Vice President - Marketing and Employee/External Affairs since 1996. He previously served as Vice President - Customer Operations from 1989 to 1996. Responsible for corporate communications, marketing, govermental affairs, economic development, safety and health, employee relations and human resources-coastal region.
Robert G. Moore - Vice President - Power Generation and Transmission of GULF and Vice President of Fossil Generation of SCS since 1997. He previously served as Plant Manager - Bowen at GEORGIA. Responsible for the generation and transmission of electricity and bulk power maketing efforts.
Arlan E. Scarbrough - Vice President - Finance since 1980. Responsible for all accounting, financial and regulatory matters.
Involvement in certain legal proceedings. None.
III-8
MISSISSIPPI
Identification of directors of MISSISSIPPI.
Dwight H. Evans President and Chief Executive Officer Age 50 Served as Director since 3-27-95
Paul J. DeNicola (1) Age 50 Served as Director since 5-1-89
Edwin E. Downer (1) Age 67 Served as Director since 4-24-84
Robert S. Gaddis (1) Age 67 Served as Director since 1-21-86
Aubrey K. Lucas (1) Age 64 Served as Director since 4-24-84
George A. Schloegel (1) Age 58 Served as Director since 7-26-95
Philip J. Terrell (1) Age 45 Served as Director since 2-22-95
N. Eugene Warr (1) Age 63 Served as Director since 1-21-86
(1) No position other than Director.
Each of the above is currently a director of MISSISSIPPI, serving a term running from the last annual meeting of MISSISSIPPI's stockholder (April 7, 1998) for one year until the next annual meeting or until his 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 MISSISSIPPI acting solely in their capacities as such. Identification of executive officers of MISSISSIPPI.
Dwight H. Evans President, Chief Executive Officer and Director Age 50 Served as Executive Officer since 3-27-95
H. E. Blakeslee Vice President - Customer Services and Marketing Age 58 Served as Executive Officer since 1-25-84
Andrew J. Dearman, III Vice President - Power Generation and Delivery Age 45 Served as Executive Officer since 4-23-97
Don E. Mason Vice President - External Affairs and Corporate Services Age 57 Served as Executive Officer since 7-27-83
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer Age 46 Served as Executive Officer since 1-1-95
Each of the above is currently an executive officer of MISSISSIPPI, serving a term running from the last annual meeting of the directors (May 7, 1998) for one year until the next annual meeting or until his 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 was or is to be selected as an officer, other than any arrangements or understandings with officers of MISSISSIPPI acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
III-9
Business experience.
Dwight H. Evans - President and Chief Executive Officer since 1995. He previously served as Executive Vice President - External Affairs of GEORGIA from 1989 to 1995.
Paul J. DeNicola - President and Chief Executive Officer of SCS effective 1994. Executive Vice President and Group Executive of SOUTHERN since 1991. Executive Vice President of SCS from 1991 through 1993. Director of SOUTHERN, SAVANNAH and GULF.
Edwin E. Downer - Business consultant specializing in economic analysis, management controls and procedural studies, Meridian, Mississippi.
Robert S. Gaddis - Chairman of the Advisory Board of Trustmark National Bank, Laurel, Mississippi.
Aubrey K. Lucas - President Emeritus and Distinguished Professor of Higher Education at the University of Southern Mississippi, Hattiesburg, Mississippi.
George A. Schloegel - President of Hancock Bank. President, Chief Executive Officer and Director of Hancock Bank Securities Corporation. Vice Chairman of Hancock Holding Company. Director of Hancock Bank - Mississippi and Hancock Bank - Louisiana.
Philip J. Terrell - Superintendent of Pass Christian Public School District and adjunct professor at William Carey College.
N. Eugene Warr - Retailer (Biloxi and Gulfport, Mississippi). Director of Coast Community Bank, formerly SouthTrust Bank of Mississippi, Biloxi, Mississippi.
H. E. Blakeslee - Vice President - Customer Services and Marketing since 1984. Responsible for rate design, revenue forecasting, marketing, district operations, corporate compliance, distribution engineering, customer accounting, vehicle maintenance centers and customer call center.
Andrew J. Dearman, III - Vice President - Power Generation and Delivery since 1997. Responsible for generating plants, environmental quality, fuel services, power generation technical services, transmission, system planning, bulk power contracts, system operations and control, system protection and real estate. He served as Vice President - Southern Division of ALABAMA from 1995 to May 1997, and Division Manager - Customer Service of ALABAMA from 1989 to 1995.
Don E. Mason - Vice President- External Affairs and Corporate Services since 1983. Responsible for external affairs, corporate communications, security, risk management, economic development and general services, as well as the human resources function.
Michael W. Southern - Vice President, Secretary, Treasurer and Chief Financial Officer since 1995. Responsible for accounting, secretary/treasury, corporate planning, procurement and information resources. He previously served as Director of Corporate Finance of SCS from 1994 to 1995 and Director of Financial Planning of SCS from 1990 to 1994.
Involvement in certain legal proceedings. None.
III-10
SAVANNAH
Identification of directors of SAVANNAH.
G. Edison Holland, Jr. President and Chief Executive Officer Age 46 Served as Director since 7-15-97
Archie H. Davis (1) Age 57 Served as Director since 2-18-97
Paul J. DeNicola (1) Age 50 Served as Director since 3-14-91
Walter D. Gnann (1) Age 63 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 53 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 62 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 19, 1998) 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/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 46 Served as Executive Officer since 7-15-97
W. Miles Greer Vice President - Customer Operations, Marketing and External Affairs Age 55 Served as Executive Officer since 11-20-85
Kirby R. Willis Vice President, Treasurer, Chief Financial Officer and Assistant Corporate Secretary Age 47 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 21, 1998 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.
Family relationships. None.
Business experience.
G. Edison Holland, Jr. - Elected President and Chief Executive Officer in 1997. Vice President - 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.
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. Director of Bryan Bank & Trust.
III-11
Paul J. DeNicola - President and Chief Executive Officer of SCS since 1994. Executive Vice President and Group Executive of SOUTHERN since 1991. Executive Vice President of SCS from 1991 through 1993. Director of SOUTHERN, GULF and MISSISSIPPI.
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc., Springfield, Georgia. Past Chairman of the Development Authority of Effingham County, 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, Cerulean Corporation and Blue Cross/Blue Shield of Georgia.
W. Miles Greer - Vice President - Customer Operations, Marketing and External Affairs since 1998. Responsible for marketing, customer services, transmission and distribution, engineering, system operation and external affairs. He previously served as Vice President of Marketing and Customer Service from 1994 to 1998.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since 1994 and Assistant Corporate Secretary effective 1998. Responsible primarily for all accounting, financial, information resources, labor relations, corporate services, environmental and safety activities. He previously served as Treasurer, Controller and Assistant Secretary from 1991 to 1993.
Involvement in certain legal proceedings. None
Section 16(a) Beneficial Ownership Reporting Compliance.
GEORGIA's Mr. Franklin filed one late report with the SEC representing one transaction in SOUTHERN common stock.
III-12
Item 11. EXECUTIVE COMPENSATION
Summary Compensation Tables. The following tables set forth information concerning any Chief Executive Officer and the four most highly compensated executive officers whose total annual salary and bonus exceeded $100,000 during 1998 for each of the operating affiliates (ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH).
Key terms used in this Item will have the following meanings:-
AME.........................Above-market earnings on deferred compensation ESP.........................Employee Savings Plan ESOP........................Employee Stock Ownership Plan SBP.........................Supplemental Benefit Plan ERISA.......................Employee Retirement Income Security Act
III-13
III-14
III-15
III-16
III-17
III-18
III-19
III-20
III-21
III-22
III-23
III-24
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Pension Plan Table. The following table sets forth the estimated combined annual pension benefits under the Pension, Supplemental Defined Benefit, and Supplemental Executive Retirement Plans in effect during 1998 for the named executives at ALABAMA, GEORGIA, GULF and MISSISSIPPI and Mr. Holland at SAVANNAH. Employee compensation covered by the Pension, Supplemental Benefit, and Supplemental Executive Retirement Plans 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 Tables on pages III-13 through III-18).
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, 1998, the applicable compensation levels and years of accredited service are presented in the following tables:
ALABAMA Compensation Accredited Name Level Years of Service
Elmer B. Harris $844,132 39 Banks H. Farris 391,968 39 William B. Hutchins, III 319,544 32 Michael D. Garrett 268,316 30 Earl B. Parsons, Jr. 269,744 37
III-25
GEORGIA Compensation Accredited Name Level Years of Service
H. Allen Franklin $920,468 27 David M. Ratcliffe 506,316 27 Gene R. Hodges 342,084 34 Warren Y. Jobe1 343,808 34 Robert H. Haubein, Jr. 326,044 31
GULF Compensation Accredited Name Level Years of Service
Travis J. Bowden2 $481,924 32 Arlan E. Scarbrough 244,832 35 John E. Hodges, Jr. 248,136 32 Francis M. Fisher, Jr. 227,144 27 Robert G. Moore 183,044 25
MISSISSIPPI Compensation Accredited Name Level Years of Service
Dwight H. Evans $398,224 27 H. E. Blakeslee 274,248 33 Don E. Mason 264,564 32 Michael W. Southern 221,140 23 Andrew J. Dearman, III 185,060 23
SAVANNAH Compensation Accredited Name Level Years of Service
G. Edison Holland, Jr.3 $280,560 15 W. Miles Greer 143,858 14 Kirby R. Willis 137,972 24
- - - - - - - --------------------------- 1 The number of accredited years of service includes 7 years and 8 months credited to Mr. Jobe pursuant to a supplemental pension agreement. 2 The number of accredited years of service includes 10 years credited to Mr. Bowden pursuant to a supplemental pension agreement. 3 The number of accredited years of service includes 9 years and 3 months credited to Mr. Holland pursuant to a supplemental pension agreement.
III-26
Effective January 1, 1998, SAVANNAH merged its pension plan into SOUTHERN's 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 1998 which are payable to SAVANNAH's named executives, except Mr.Holland who participates in the plans described on page III-25, 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
$ 90,000 $ 63,000 $ 63,000 $ 63,000 120,000 84,000 84,000 84,000 150,000 105,000 105,000 105,000 180,000 126,000 126,000 126,000 210,000 147,000 147,000 147,000 260,000 182,000 182,000 182,000 280,000 196,000 196,000 196,000 300,000 210,000 210,000 210,000
III-27
Compensation of Directors.
Standard Arrangements. The following table presents compensation paid to the directors, during 1998 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. All or a portion of these fees payable in cash may be deferred under the Deferred Compensation Plan until membership on the board is terminated or may be payable in SOUTHERN common stock at the election of the director.
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.
Other Arrangements. No director received other compensation for services as a director during the year ending December 31, 1998 in addition to or in lieu of that specified by the standard arrangements specified above.
III-28
Employment Contracts and Termination of Employment and Change in Control Arrangements.
Each registrant 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 and stock appreciation rights 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 the agreement.
A 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.
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.
On February 28, 1998, SOUTHERN and GEORGIA entered into a Deferred Compensation Agreement with Mr. Franklin. On the fifth anniversary of the Agreement, if Mr. Franklin is still employed by SOUTHERN or one of its subsidiaries, he will receive the cash value of the number of shares of common stock that could have been purchased for $500,000 on February 28, 1998, and on which dividends were reinvested throughout the five-year period. If certain performance goals are met, Mr. Franklin also will receive the estimated income tax expense on the compensation. Mr. Franklin may elect to defer receipt of the award until termination of employment.
SOUTHERN and GEORGIA entered into a Deferred Compensation Agreement with Mr. Jobe. Mr. Jobe becomes eligible for benefits under the terms of this Agreement if one of the following Eligibility Events occurs: (1) Mr. Jobe terminates employment with SOUTHERN or one of its subsidiaries on or after attaining age sixty-two and enters into a release as provided by the Agreement; or (2) Mr. Jobe, after entering into this Agreement but while employed by SOUTHERN or one of its subsidiaries, becomes totally and permanently disabled as determined by a medical doctor selected by SOUTHERN and enters into a release as provided by the Agreement. Upon the occurrence of an eligibility event as detailed in item (1) above, SOUTHERN agrees to pay Mr. Jobe a lump sum amount equal to two times base pay in effect at the time of the eligibility event; a lump sum amount equal to the present value of the monthly Early Retirement Reduction Percentage of Employee's Accrued Retirement Income under the pension plan, plus an amount equal to the reduction of Mr. Jobe's monthly Supplemental Employee Retirement Plan benefit; and consulting fees for services provided by Mr. Jobe as an independent contractor. Upon the occurrence of an eligibility event as detailed in item (2) above, SOUTHERN agrees to pay Mr. Jobe a lump sum amount
III-29
Employment Contracts and Termination of Employment and Change in Control Arrangements. (continued)
equal to two times base pay in effect at the time of the eligibility event; and a lump sum amount equal to the present value of the monthly Early Retirement Reduction Percentage of Employee's Accrued Retirement Income under the pension plan, plus an amount equal to the reduction of Mr. Jobe's monthly Supplemental Employee Retirement Plan benefit.
Report on Repricing of Options.
None.
Compensation Committee Interlocks and Insider Participation.
None.
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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 registrants: ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH.
Security Ownership of Management. The following table shows the number of shares of SOUTHERN common stock and operating subsidiary preferred stock owned by the directors, nominees and executive officers as of December 31, 1998. 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 of the respective classes outstanding on December 31, 1998.
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2)
ALABAMA
Whit Armstrong SOUTHERN Common 16,949
David J. Cooper, Sr. SOUTHERN Common 379
A. William Dahlberg SOUTHERN Common 355,291
Peter V. Gregerson, Sr. SOUTHERN Common 575
Elmer B. Harris SOUTHERN Common 222,887
Carl E. Jones, Jr. SOUTHERN Common 11,403
Patricia M. King SOUTHERN Common 177
James K. Lowder SOUTHERN Common 5,47
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Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1)(2)
Thomas C. Meredith SOUTHERN Common 18
William V. Muse SOUTHERN Common 575
John T. Porter SOUTHERN Common 1,008
Robert D. Powers SOUTHERN Common 575
Andreas Renschler SOUTHERN Common 410
C. Dowd Ritter SOUTHERN Common 177
William J. Rushton, III SOUTHERN Common 8,148
James H. Sanford SOUTHERN Common 511
John C. Webb, IV SOUTHERN Common 19,572
Banks H. Farris SOUTHERN Common 28,112
Michael D. Garrett SOUTHERN Common 8,087
William B. Hutchins, III SOUTHERN Common 48,307
Earl B. Parsons Jr. SOUTHERN Common 10,895
The directors, nominees, and executive officers as a group SOUTHERN Common 728,635
GEORGIA
Daniel P. Amos SOUTHERN Common 168
Juanita P. Baranco SOUTHERN Common 168
A. William Dahlberg SOUTHERN Common 355,291
W. A. Fickling, Jr. SOUTHERN Common 1,069
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Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned(1)(2)
H. Allen Franklin SOUTHERN Common 177,239
L. G. Hardman III SOUTHERN Common 16,062
Warren Y. Jobe SOUTHERN Common 70,034 GEORGIA Preferred 200
James R. Lientz, Jr. SOUTHERN Common 946
G. Joseph Prendergast SOUTHERN Common 961
Herman J. Russell SOUTHERN Common 10,710
Gloria M. Shatto SOUTHERN Common 18,830 GEORGIA Preferred 1,200
W. J. Vereen SOUTHERN Common 496
Carl Ware SOUTHERN Common 646
William C. Archer, III SOUTHERN Common 17,500
Robert H. Haubein, Jr. SOUTHERN Common 29,002
Gene R. Hodges SOUTHERN Common 43,245
David M. Ratcliffe SOUTHERN Common 79,206
The directors, nominees and executive officers as a group SOUTHERN Common 917,255 GEORGIA Preferred 1,650
III-33
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2)
GULF
Travis J. Bowden SOUTHERN Common 34,889
Paul J. DeNicola SOUTHERN Common 139,642
Fred C. Donovan, Sr. SOUTHERN Common 637
W. Deck Hull, Jr. SOUTHERN Common 2,549
Joseph K. Tannehill SOUTHERN Common 4,439
Barbara H. Thames SOUTHERN Common 160
Francis M. Fisher, Jr. SOUTHERN Common 6,604
John E. Hodges, Jr. SOUTHERN Common 37,925
Robert G. Moore SOUTHERN Common 20,729
Arlan E. Scarbrough SOUTHERN Common 20,039
The directors, nominees and executive officers as a group SOUTHERN Common 267,502
MISSISSIPPI
Paul J. DeNicola SOUTHERN Common 139,642
Edwin E. Downer SOUTHERN Common 5,365
Dwight H. Evans SOUTHERN Common 62,158 GEORGIA Preferred 400 MISSISSIPPI Preferred 200 SOUTHERN Preferred 200
Robert S. Gaddis SOUTHERN Common 3,183
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Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2)
Aubrey K. Lucas SOUTHERN Common 1,940
George A. Schloegel SOUTHERN Common 485
Philip J. Terrell SOUTHERN Common 1,103
N. Eugene Warr SOUTHERN Common 688
H. E. Blakeslee SOUTHERN Common 26,201
Andrew J. Dearman, III SOUTHERN Common 11,674
Don E. Mason SOUTHERN Common 34,258
Michael W. Southern SOUTHERN Common 7,430
The directors, nominees and executive officers as a group SOUTHERN Common 294,125 GEORGIA Preferred 400 MISSISSIPPI Preferred 233 SOUTHERN Preferred 200
SAVANNAH
Archie H. Davis SOUTHERN Common 190
Paul J. DeNicola SOUTHERN Common 139,642
Walter D. Gnann SOUTHERN Common 1,833
G. Edison Holland SOUTHERN Common 32,589
Robert B. Miller, III SOUTHERN Common 2,203
Arnold M. Tenenbaum SOUTHERN Common 793
III-35
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2)
W. Miles Greer SOUTHERN Common 9,599
Kirby R. Willis SOUTHERN Common 10,996
The directors, nominees and executive officers as a group SOUTHERN Common 185,772
Changes in control. SOUTHERN and the operating affiliates know of no arrangements which may at a subsequent date result in any change in control.
(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, as follows: Mr. Blakeslee, 21,932 shares; Mr. Dahlberg, 289,787 shares; Mr. DeNicola, 103,158 shares; Mr. Evans, 40,274 shares; Mr. Farris, 24,020 shares; Mr. Franklin, 149,760 shares; Mr. Greer, 6,655 shares; Mr. Harris, 183,510 shares; Mr. Haubein, 26,696 shares; Mr. G. R. Hodges, 26,842 shares; Mr. J. E. Hodges, 15,640 shares; Mr. Holland, 30,209 shares; Mr. Hutchins, 32,521 shares; Mr. Jobe, 39,645 shares; Mr. Mason, 11,421 shares; Mr. Southern, 7,942 shares, and Mr. Willis, 6,192 shares. Also included are shares of SOUTHERN common stock held by the spouses of the following directors: Mr. Bowden, 500 shares; Mr. DeNicola, 12,072 shares; Mr. Gaddis; 1,200 shares; Mr. Hardman, 100 shares; Mr. Harris, 310 shares, and Dr. Shatto, 14,113 shares. Also included are shares of common stock held in the Southern Company Deferred Stock Trust of which certain directors have the power to direct the voting, as follows: Mr. Hardman, 6,714 shares and Dr. Shatto, 799 shares. Also included are 1,200 shares of GEORGIA preferred stock held by Dr. Shatto's spouse.
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Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ALABAMA
Transactions with management and others.
Mr. Whit Armstrong is President, Chairman and Chief Executive Officer of The Citizens Bank, Enterprise, Alabama; Mr. Carl E. Jones, Jr. is President and Chief Executive Officer of Regions Financial Corporation, Birmingham, Alabama; Mr. Wallace D. Malone is Chairman and Chief Executive Officer of SouthTrust Corporation, Birmingham, Alabama. Mr. C. Dowd Ritter is Chairman, President, Chief Executive Officer and Director of AmSouth Bancorporation and AmSouth Bank, Birmingham, Alabama. During 1998, these banks furnished a number of regular banking services in the ordinary course of business to ALABAMA. ALABAMA intends to maintain normal banking relations with all the aforesaid banks in the future.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
GEORGIA
Transactions with management and others.
Mr. L. G. Hardman III is Chairman of the Board of The First National Bank of Commerce, Georgia; Mr. James R. Lientz, Jr. is President of NationsBank Mid-South Banking Group, Atlanta, Georgia; Mr. G. Joseph Prendergast is Senior Executive Vice President, Wachovia Corporation, Atlanta, Georgia; and Mr. Herman J. Russell is Chairman of the Board of Citizens Trust Bank, Atlanta, Georgia. During 1998, these banks furnished a number of regular banking services in the ordinary course of business to GEORGIA. GEORGIA intends to maintain normal banking relations with all the aforesaid banks in the future.
In 1998, GEORGIA leased a building from Riverside Manufacturing Co. for approximately $84,075. Also,Riverside Manufacturing sold to GEORGIA fire retardant uniforms for $88,646. Mr. William J. Vereen is Chief Executive Officer, President, Treasurer and Director of Riverside Manufacturing Co.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None. GULF
Transactions with management and others. None
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
MISSISSIPPI
Transactions with management and others.
Mr. Robert S. Gaddis is Chairman of the Advisory Board of Trustmark National Bank, Laurel, Mississippi; Mr. George A. Schloegel is President of Hancock Bank, Gulfport, Mississippi. During 1998, these banks furnished a number of regular banking services in the ordinary course of business to MISSISSIPPI. MISSISSIPPI intends to maintain normal banking relations with the aforesaid banks in the future.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
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SAVANNAH
Transactions with management and others. None
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
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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