Item 1. BUSINESS
SOUTHERN was incorporated under the laws of Delaware on November 9, 1945. SOUTHERN is domesticated under the laws of Georgia and is qualified to do business as a foreign corporation under the laws of Alabama. SOUTHERN owns all the outstanding common stock of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, each of which is an operating public utility company. The integrated Southeast utilities supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively. More particular information relating to each of the integrated Southeast utilities is as follows:
ALABAMA is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company and Houston Power Company. The predecessor Alabama Power Company had had a continuous existence since its incorporation in 1906.
GEORGIA was incorporated under the laws of the State of Georgia on June 26, 1930, and admitted to do business in Alabama on September 15, 1948.
GULF is a corporation which was organized under the laws of the State of Maine on November 2, 1925, and admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984.
MISSISSIPPI was incorporated under the laws of the State of Mississippi on July 12, 1972, was admitted to do business in Alabama on November 28, 1972, and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924, and was admitted to do business in Mississippi on December 23, 1924, and in Alabama on December 7, 1962.
SAVANNAH is a corporation existing under the laws of the State of Georgia; its charter was granted by the Secretary of State on August 5, 1921.
SOUTHERN also owns all the outstanding common stock of Southern Energy, Southern LINC, Southern Nuclear, SCS, Energy Solutions and other direct and indirect subsidiaries. Southern Energy acquires, develops, builds, owns and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Southern Energy businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States. A further description of Southern Energy's business and organization follows later in this section under "Southern Energy." Southern LINC provides digital wireless communications services to SOUTHERN's integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Nuclear provides services to ALABAMA and GEORGIA's nuclear plants. Energy Solutions develops new business opportunities related to energy products and services.
ALABAMA and GEORGIA each own 50% of the outstanding common stock of SEGCO. SEGCO owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000 volt transmission lines extending from Plant Gaston to the Georgia state line at which point connection is made with the GEORGIA transmission line system.
Reference is also made to Note 14 to the financial statements of SOUTHERN in Item 8 herein for additional information regarding SOUTHERN's segment and related information.
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The SOUTHERN System
Integrated Southeast Utilities
The transmission facilities of each of the integrated Southeast utilities are connected to the respective company's own generating plants and other sources of power and are interconnected with the transmission facilities of the other integrated Southeast utilities and SEGCO by means of heavy-duty high voltage lines. (In the case of GEORGIA's integrated transmission system, see Item 1 - BUSINESS - "Territory Served by the Integrated Southeast Utilities" herein.)
Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. Additionally, the integrated Southeast utilities have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy Corporation, South Carolina Electric & Gas Company and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The integrated Southeast utilities have joined with other utilities in the Southeast (including those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the integrated Southeast utilities are represented on the National Electric Reliability Council.
An intra-system interchange agreement provides for coordinating operations of the power producing facilities of the integrated Southeast utilities and the capacities available to such companies from non-affiliated sources and for the pooling of surplus energy available for interchange. Coordinated operation of the entire interconnected system is conducted through a central power supply coordination office maintained by SCS. The available sources of energy are allocated to the integrated Southeast utilities to provide the most economical sources of power consistent with good operation. The resulting benefits and savings are apportioned among the integrated Southeast utilities.
Reference is made to each registrant's "Management's Discussion and Analysis - - Future Earnings Potential" in Item 7 for information relating to the FERC's final rule issued on December 20, 1999, relating to RTOs.
SCS has contracted with SOUTHERN, each integrated Southeast utility, 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 integrated Southeast utilities certain services which are furnished at cost.
Southern Nuclear has contracts with ALABAMA to operate the Farley Nuclear Plant, and with GEORGIA to operate Plants Hatch and Vogtle. See Item 1 - BUSINESS - "Regulation - Atomic Energy Act of 1954" herein.
Southern Energy
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 Energy is a global company engaged in electricity generation and distribution, integrated utility operations and energy marketing. Southern Energy is one of the world's largest independent power producers with ownership interests in generating facilities with a total capacity of 28,000 megawatts, of which Southern Energy has net ownership or control of over 14,000 megawatts. In addition, Southern Energy has projects under construction or advanced development in which it will have additional net ownership interests totaling 5,000 megawatts. SOUTHERN has filed with the SEC a request to invest up to nearly $6 billion in Southern Energy's domestic and international business. The current SEC authority is $4.1 billion,
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of which $2.7 billion has been invested as of December 31, 1999. For additional information relating to Southern Energy's business strategy, reference is made to Item 7, SOUTHERN's "Management's Discussion and Analysis - Future Earnings Potential" herein.
Approximately 60% of the net megawatts of generating capacity currently owned by Southern Energy is located in the United States, with the remainder in England, Germany, the Philippines, China, Brazil, Argentina, Chile, the Bahamas and Trinidad and Tobago. In the United States during 1999, Southern Energy completed the acquisition of 3,065 megawatts from Pacific Gas & Electric Company in California and 1,794 megawatts from Orange & Rockland Utilities, Inc. and Consolidated Edison Company of New York, Inc. in the State of New York. These North American acquisitions, together with acquisitions completed prior to 1999, are a component of Southern Energy's strategy of investing in generating assets which are expected to be linked to Southern Energy's trading and marketing activities. Also in 1999, Southern Energy completed the acquisition of a 9.99% ownership interest in Shandong International Power Development Company Limited which currently owns generating facilities in China with installed capacity of 4,435 megawatts.
In 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 Integrated Southeast Utilities
The integrated Southeast utilities and SEGCO, at December 31, 1999, 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 -----------
------------------------- ----------------------------------------- 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 899,612 (8) Vogtle Augusta, GA 1,060,240 (9) ----------- GEORGIA Total 1,959,852 ----------- Total Nuclear Steam 3,679,852 -----------
Combustion Turbines Greene County Demopolis, AL ALABAMA Total 720,000 -----------
Arkwright Macon, GA 30,580 Atkinson Atlanta, GA 78,720 Bowen Cartersville, GA 39,400 Intercession City Intercession City, FL 47,333 (10) McDonough Atlanta, GA 78,800 McIntosh Units 1,2,3,4,7,8 Effingham County, GA 480,000 McManus Brunswick, GA 481,700 Mitchell Albany, GA 118,200 Robins Warner Robins, GA 160,000 Wilson Augusta, GA 354,100 Wansley Carrollton, GA 26,322 (5) ---------- GEORGIA Total 1,895,155 ----------
Lansing Smith Unit A Panama City, FL 39,400 Pea Ridge Units 1-3 Pea Ridge, FL 14,250 ------ GULF Total 53,650 ------ Chevron Cogenerating Station Pascagoula, MS 147,292 (11) Sweatt Meridian, MS 39,400 Watson Gulfport, MS 39,360 --------- MISSISSIPPI Total 226,052 ---------
------------------------------------------------- -----------------
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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 -------
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 31,196,193 ==========
------------------------------------------------ -----------------
Notes: (1) For additional information regarding facilities jointly-owned with non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein. (2) Owned by ALABAMA and MISSISSIPPI as tenants in common in the proportions of 60% and 40%, respectively. (3) Excludes the capacity owned by AEC. (4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for GULF is 25% of Unit 3. (5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity. (6) Represents 50% of the plant which is owned as tenants in common by GULF and MISSISSIPPI. (7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS herein.) (8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity. (9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity. (10) Capacity shown represents 33-1/3% of total plant capacity. GEORGIA owns a 1/3 interest in the unit with 100% use of the unit from June through September. FPC operates the unit. (11) Generation is dedicated to a single industrial customer. (12) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity. OPC operates the plant.
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Except as discussed below under "Titles to Property," the principal plants and other important units of the integrated Southeast utilities and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.
MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a forty-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 1999, the unamortized portion of this cost was $35 million.
The all-time maximum demand on the integrated Southeast utilities and SEGCO was 30,578,200 kilowatts and occurred in August 1999. This amount excludes demand served by capacity retained by MEAG and Dalton and excludes demand associated with power purchased from OPC and SEPA by its preference customers. The reserve margin for the integrated Southeast utilities and SEGCO at that time was 8.5%. 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.)
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Other Electric Properties - Southern Energy
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, 1999, was as follows:
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Notes: (1) Represents megawatts of capacity under a concession agreement expiring in the year 2023. In early 2000, Southern Energy announced an agreement to sell Alicura, its Argentinean assets, substantially at the adjusted carrying value with no material gain or loss expected to be recognized in 2000. (2) Cogeneration facility.
Jointly-Owned Facilities
ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in certain generating plants and other related facilities to or from non-affiliated parties. The percentages of ownership resulting from these transactions are as follows:
ALABAMA and GEORGIA have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain and Intercession City, as described below) as agent for the joint owners.
In addition, GEORGIA has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG's bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the 1987 and 1990 write-offs of Plant Vogtle costs, the cost of such capacity and energy is included in purchased power from non-affiliates in GEORGIA's Statements of Income in Item 8 herein.
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 is 25.4 percent. On January 14, 1998, the Georgia PSC ordered that the Company
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be allowed approximately $108 million of its $142 million investment in the plant in rate base as of December 31, 1998. GEORGIA appealed the Georgia PSC's order. Under the rate order approved by the Georgia PSC on December 18, 1998, GEORGIA accepted the rate base allowance and, 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 integrated Southeast utilities' and SEGCO's interests in the principal plants (other than certain pollution control facilities, one small hydroelectric generating station leased by GEORGIA and the land on which five combustion turbine generators of MISSISSIPPI are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the liens of applicable mortgage indentures (except for SEGCO) and to excepted encumbrances as defined therein. The integrated Southeast utilities own the fee interests in certain of their principal plants as tenants in common. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) Properties such as electric transmission and distribution lines and steam heating mains are constructed principally on rights-of-way which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In substantially all of its coal reserve lands, SEGCO owns or will own the coal only, with adequate rights for the mining and removal thereof.
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Item 3.
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. ALABAMA, GEORGIA and SCS (United States District Court for the Northern District of Georgia)
Reference is made to Note 3 in each of the registrant's financial statements in Item 8 herein.
(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 Lake Martin Litigation" and "Lake Martin 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 "Other 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).
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8 herein under the caption "Mobile Energy Services Petition for Bankruptcy".
(5) State of Minas Gerais v. Southern Electric Brasil Participacoes Ltda. (Appellate Court of the State of Minas Gerais)
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8 herein under the caption "Southern Energy Brazilian Investment".
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation - - Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's financial statements in Item 8 herein for a description of certain other administrative and legal proceedings discussed therein.
Additionally, each of the integrated Southeast utilities, 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, 1999.
A. W. Dahlberg Chairman, Chief Executive Officer, and Director Age 59 Elected Director in 1985 and Chairman and Chief Executive Officer effective March 1995. Also served as President from January 1994 to June 1999.
H. Allen Franklin President, Chief Operating Officer and Director Age 55 Elected Director in 1988 and President and Chief Operating Officer effective June 1999. Previously served as President and Chief Executive Officer of GEORGIA from January 1994 to June 1999.
S. Marce Fuller Executive Vice President Age 39 Elected in 1999. She also has served as President and Chief Executive Officer of Southern Energy since July 1999. Previously Executive Vice President of Southern Energy from October 1998 to July 1999; Senior Vice President from May 1996 to October 1998; and Vice President from February 1994 to May 1996. Also served as President and Chief Executive Officer of SCEM from February 1998 to November 1999.
Elmer B. Harris Executive Vice President and Director Age 60 Elected Director in 1989 and Executive Vice President in 1991. He also has served as President and Chief Executive Officer of ALABAMA since 1989.
David M. Ratcliffe Executive Vice President Age 51 Elected in 1999. He also has served as President and Chief Executive Officer of GEORGIA since June 1999. Previously served as Executive Vice President and Chief Financial Officer of GEORGIA from March 1998 to June 1999; Senior Vice President of SOUTHERN from March 1995 to March 1998; and as President and Chief Executive Officer of MISSISSIPPI from 1991 to March 1995.
Stephen A. Wakefield Senior Vice President and General Counsel Age 59 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 60 Elected in 1986. He also has served as Executive Vice President of SCS since 1986.
C. Alan Martin Vice President Age 51 Elected in 1998; served as Chief Marketing Officer for the SOUTHERN system. Previously Vice President of Human Resources of SOUTHERN from 1995 to February 1998. Effective January 1, 2000; elected Executive Vice President of ALABAMA.
Charles D. McCrary Vice President Age 48 Elected in 1998; serves as Chief Production Officer for the SOUTHERN system. He also serves as Executive Vice President of GEORGIA since May 1998. Previously, he served as Executive Vice President of ALABAMA from 1994 through April 1998.
W. G. Hairston, III Age 54 President and Chief Executive Officer of Southern Nuclear since 1993.
The officers of SOUTHERN were elected for a term running from June 1, 1999 for one year until the next annual meeting of directors or until their successors are elected and have qualified, except for Ms. Fuller who was elected October 18, 1999.
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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 $29-5/8 $23-1/4 Second Quarter 29-3/16 22-3/4 Third Quarter 28 25 Fourth Quarter 27-1/8 22-1/16
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
-------------------- --------------- --- --------------
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 29, 2000, the closing price of SOUTHERN's common stock was $22-3/16.
(b) Number of SOUTHERN's common stockholders at December 31, 1999: 174,179
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 1999 1998 ------------------- --------- ------------- ----------
SOUTHERN First $233,879 $232,449 Second 233,445 233,623 Third 228,690 233,763 Fourth 225,470 233,506
ALABAMA First 98,000 90,400 Second 98,400 90,500 Third 99,700 90,800 Fourth 103,500 95,400
GEORGIA First 133,100 132,100 Second 133,700 132,300 Third 135,500 132,700 Fourth 140,700 139,500
GULF First 15,000 14,100 Second 15,100 14,100 Third 15,300 14,100 Fourth 15,900 14,900
MISSISSIPPI First 13,800 12,700 Second 13,800 12,800 Third 14,000 12,800 Fourth 14,500 13,400
SAVANNAH First 6,200 5,800 Second 6,200 5,800 Third 6,300 5,800 Fourth 6,500 6,100 ------------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of 1998 and 1999. The dividend paid on SOUTHERN's common stock for the first quarter of 2000 was 33.5(cent) per share.
The amount of dividends on their common stock that may be paid by the subsidiary registrants is restricted in accordance with their first mortgage bond indenture. The
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amounts of earnings retained in the business and the amounts restricted against the payment of cash dividends on common stock at December 31, 1999, were as follows:
-------------------- ------------------ --- -------------- Retained Restricted Earnings Amount ------------------ -------------- (in millions) ALABAMA $1,225 $ 796 GEORGIA 1,778 897 GULF 163 127 MISSISSIPPI 172 118 SAVANNAH 111 68 Consolidated 4,232 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-46 and II-47.
ALABAMA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-78 and II-79.
GEORGIA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-111 and II-112.
GULF. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-140 and II-141.
MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-169 and II-170.
SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-195 and II-196.
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-51 through II-58.
GEORGIA. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-83 through II-90.
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-116 through II-123.
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-145 through II-151.
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-174 through II-180.
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 II-31 through II-32, respectively.
Reference is also made to "Management's Discussion and Analysis - Exposure to Market Risks" in Item 7 of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH contained herein at pages II-55, II-87, II-120, II-148, and II-177, respectively.
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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
II-4 THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
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MANAGEMENT'S REPORT Southern Company and Subsidiary Companies 1999 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 and Chief Executive Officer
/s/W. L. Westbrook W. L. Westbrook Financial Vice President, Chief Financial Officer, and Treasurer
February 16, 2000
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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, 1999 and 1998, and the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements (pages II-20 through II-45) referred to above present fairly, in all material respects, the financial position of Southern Company and subsidiary companies as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Atlanta, Georgia February 16, 2000
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 1999 Annual Report
Results of Operations
Overview of Consolidated Earnings
Southern Company's 1999 earnings of $1.28 billion or $1.86 per share established a new record high. Higher earnings were primarily driven by strong growth in the competitive energy supply business outside the southeastern United States. The traditional business of selling electricity in the Southeast continued to remain strong. However, reported earnings in both 1999 and 1998 reflected significant items not related to the normal day-to-day business activities. After excluding these items, earnings for 1999 were $1.30 billion or $1.90 per share compared with $1.23 billion or $1.76 per share in 1998.
Southern Energy, Inc. (Southern Energy) is the Southern Company subsidiary that owns and manages its international operations and develops and owns its competitive energy supply business in North America outside the Southeast. Southern Energy earnings accounted for approximately 26 percent of Southern Company's reported net income in 1999. Amortization of goodwill related to Southern Energy investments reduced earnings per share by 5 cents in 1999 and 4 cents in 1998.
A reconciliation of reported earnings to earnings excluding non-day to day business items and the related explanations are as follows:
Consolidated Earnings Net Income Per Share ------------- -------------- 1999 1998 1999 1998 ------------- -------------- (in millions) Earnings as reported $1,276 $ 977 $1.86 $1.40 - --------------------------------------------------------------- Gain on asset sale (78) - (.11) - Write down of assets: South American investments - 200 - .29 Rocky Mountain plant - 21 - .03 Mobile Energy 69 - .10 - Work force reductions 50 20 .07 .03 Other (14) 7 (.02) .01 - --------------------------------------------------------------- Total adjustments 27 248 .04 .36 - --------------------------------------------------------------- Earnings as adjusted $1,303 $1,225 $1.90 $1.76 =============================================================== Amount and percent change $78 6.4% $0.14 8.0% - ---------------------------------------------------------------
Southern Energy sold the supply business of South Western Electricity in 1999, and the remaining distribution business was renamed Western Power Distribution. In 1999, Southern Energy recorded an asset impairment related to Mobile Energy Services -- see Note 3 to the financial statements. Southern Energy's write down of assets in 1998 related to investments in Argentina and Chile not meeting financial expectations, which resulted in an announced plan to sell these assets. In 1998, Georgia Power wrote down its investment in the Rocky Mountain pumped storage hydroelectric plant as a result of a settlement related to its 1998 retail rate proceeding. Work force reduction programs began in late 1999 for Bewag, a German utility in which Southern Energy has a 26 percent ownership interest. Also, the traditional business recorded costs related to workforce reductions in 1998.
Discussion of the results of operations are separated between the traditional business of the integrated Southeast utilities and Southern Energy.
Integrated Southeast Utilities
The five integrated Southeast utilities provide electric service in four states. These utilities are Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric. They comprise Southern Company's principal business segment with earnings of $1.1 billion in 1999. A condensed income statement for this business segment is as follows:
Increase (Decrease) Amount From Prior Year ------ -------------------- 1999 1999 1998 - --------------------------------------------------------------- (in millions) Operating revenues $9,125 $(238) $675 - --------------------------------------------------------------- Fuel 2,328 7 117 Purchased power 409 13 182 Other operation and maintenance 2,430 4 252 Depreciation and amortization 961 (328) 134 Taxes other than income taxes 521 13 7 Write down of assets - (34) 34 - --------------------------------------------------------------- Total operating expenses 6,649 (325) 726 - --------------------------------------------------------------- Operating income 2,476 87 (51) Other income (8) (84) 93 - --------------------------------------------------------------- Earnings before interest and taxes 2,468 3 42 Interest charges and other 720 41 48 Income taxes 675 (28) 16 - --------------------------------------------------------------- Net income $1,073 $ (10) $ (22) ===============================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
Revenues
Operating revenues changed in 1999 and 1998 as a result of the following factors: Increase (Decrease) From Prior Year ------------------ 1999 1998 - --------------------------------------------------------------- (in millions) Retail -- Growth and price changes $ 166 $258 Rate reductions (352) - Weather (86) 178 Fuel cost recovery and other 86 189 - --------------------------------------------------------------- Total retail (186) 625 - --------------------------------------------------------------- Sales for resale -- Within service area (24) (2) Outside service area (49) 12 - --------------------------------------------------------------- Total sales for resale (73) 10 Other operating revenues 21 40 - --------------------------------------------------------------- Operating revenues $(238) $675 =============================================================== Percent change (2.5)% 7.8% - ---------------------------------------------------------------
Retail revenues of $8.1 billion in 1999 declined as a result of a Georgia Power rate reduction effective January 1999. For additional information, see Note 3 to the financial statements under "Georgia Power 1998 Retail Rate Order." Customer growth in the Southeast somewhat offset the rate decrease. In 1998, retail revenues increased sharply, up 8.2 percent compared with the prior year. Continued growth in the traditional service area and the positive impact of weather on energy sales were the predominant factors causing the rise in revenues in 1998. 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 $350 million in 1999, down 6.5 percent from the prior year. This sharp decline resulted primarily from supplying less electricity under contractual agreements with certain wholesale customers in 1999, and a slight reduction in these revenues is expected in 2000. Revenues from sales for resale within the service area were $374 million in 1998, down 0.7 percent from the prior year.
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. Revenue from long-term unit power contracts have both a capacity and energy component. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components of the unit power contracts were as follows:
1999 1998 1997 - --------------------------------------------------------------- (in millions) Capacity $174 $196 $203 Energy 157 152 183 - --------------------------------------------------------------- Total $331 $348 $386 ===============================================================
Capacity revenues in 1999 and 1998 declined each year as a result of adjustments and true-ups related to contractual pricing. No significant declines in capacity are scheduled until the termination of the contracts in 2010.
Energy Sales
The changes in revenues for the traditional business in the Southeast are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1999 and the percent change by year were as follows:
Amount Percent Change (billions of ------- ---------------------------- kilowatt-hours) 1999 1999 1998 1997 - ---------------------------------------------------------------- Residential 43.4 (0.2)% 10.9% (2.2)% Commercial 43.4 4.0 7.2 2.5 Industrial 56.2 1.6 2.1 2.6 Other 0.9 1.6 3.1 (1.1) ----- Total retail 143.9 1.7 6.2 1.1 Sales for resale -- Within service area 9.4 (4.1) (0.4) (9.6) Outside service area 13.0 (0.4) (5.6) 27.7 ----- Total 166.3 1.2 4.7 2.2 ================================================================
The rate of increase in 1999 total retail energy sales was significantly lower than in 1998. Although the total number of residential customers served increased by 61,000 during the year, residential energy sales experienced a decline as a result of milder weather in 1999. The rate of growth in 1998 retail
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
energy sales was the highest one-year increase since 1986. Also, residential energy sales registered the highest annual increase in over two decades as a result of hotter-than-normal weather. Commercial and industrial sales, both in 1999 and 1998, continued to show slight gains in excess of the national averages. This reflects the strength of business and economic conditions in Southern Company's traditional service area in the southeastern United States. Energy sales to retail customers are projected to increase at an average annual rate of 2.2 percent during the period 2000 through 2010.
Sales to customers outside the service area declined by 0.4 percent in 1999 and by 5.6 percent in 1998 when compared with the respective prior year. The declines in sales were influenced by weather and fluctuations in prices for oil and natural gas, the primary fuel sources for utilities with which the company has long-term contracts. 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
Operating expenses of $6.6 billion for 1999 decreased $325 million. This decline was primarily attributable to $308 million less accelerated depreciation of plant being recorded in accordance with the 1998 Georgia Power rate order as referred to earlier. The costs to produce and deliver electricity for the traditional business in the Southeast for 1999 increased by $68 million to meet higher energy demands. All other operating and maintenance expenses declined by $44 million as a result of continued cost control programs.
In 1998, operating expenses of $7.0 billion increased $726 million compared with the prior year. The costs to produce and deliver electricity for the traditional business in 1998 increased by $359 million to meet higher energy demands. Non-production operation and maintenance expenses increased $192 million in 1998. Accelerated depreciation of certain assets increased $157 million when compared with 1997.
Fuel costs constitute the single largest expense for the integrated Southeast utilities. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated -- within the traditional business service area -- were as follows:
1999 1998 1997 - ---------------------------------------------------------------- Total generation (billions of kilowatt-hours) 165 164 160 Sources of generation (percent) -- Coal 78 77 77 Nuclear 17 16 17 Hydro 2 4 4 Oil and gas 3 3 2 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.45 1.48 1.46 - ----------------------------------------------------------------
Total fuel and purchased power costs of $2.7 billion in 1999 increased only $20 million while total energy sales increased 2.0 billion kilowatt-hours compared with the amounts recorded in 1998. Continued efforts to control energy costs helped lower the average cost of fuel per net kilowatt-hour generated in 1999. In 1998, fuel and purchased power costs increased $299 million as a result of 7.4 billion more kilowatt-hours being sold than in 1997.
Total interest charges and other financing costs in 1999 decreased $41 million from amounts reported in the previous year. The decline reflected additional refinancing of debt in 1999. Alabama Power and Georgia Power -- in accordance with their respective rate making procedures -- recorded additional accelerated amortization of premium on reacquired debt of $85 million in 1999, $33 million in 1998, and no additional amounts in 1997. Interest charges and other financing costs increased in 1998 as a result of the additional amortization being recorded.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
Southern Energy
Southern Energy's domestic and international operations provided much of Southern Company's strong financial growth in 1999. A condensed income statement for Southern Company's other significant business segment is as follows:
Increase (Decrease) Amount From Prior Year ------- --------------------- 1999 1999 1998 - ---------------------------------------------------------------- (in millions) Operating revenues $2,268 $ 365 $(1,934) - ---------------------------------------------------------------- Fuel and purchased power 937 38 (1,996) Other operation and maintenance 477 131 (22) Depreciation and amortization 322 88 40 Taxes other than income taxes 89 2 16 Write down of assets 69 (239) 308 - ---------------------------------------------------------------- Total operating expenses 1,894 20 (1,654) - ---------------------------------------------------------------- Operating income 374 345 (280) Gain on asset sales 313 272 17 Other income 433 99 100 - ---------------------------------------------------------------- Earnings before interest and taxes 1,120 716 (163) Interest charges and other 666 178 97 Income taxes 126 249 (298) - ---------------------------------------------------------------- Net income $ 328 $ 289 $ 38 ================================================================
Southern Energy recorded several significant items not related to the normal day-to-day business activities in both 1999 and 1998 as discussed earlier. Excluding these one time items, earnings were $355 million and $239 million in 1999 and 1998, respectively.
Southern Energy develops and owns competitive energy supply businesses around the world. Domestic assets include a 60 percent interest in a top ten energy trading and marketing business. International operations are principally located in China, Philippines, England, Germany, Netherlands, Brazil, Chile, Argentina, Bahamas, and Trinidad and Tobago.
Earnings by major geographical area -- excluding the one time items -- are as follows:
Increase (Decrease) Amount From Prior Year ------ -------------------- 1999 1999 1998 - ---------------------------------------------------------------- (in millions) Asia $175 $107 $27 Europe 142 9 62 North America 81 78 14 South America 1 (16) 8 Corporate and other (44) (62) 16 - ----------------------------------------------------------------
Revenues in 1999 increased 19 percent primarily as a result of acquisitions in North America of some 6,100 megawatts of generating facilities in late 1998 and in 1999. Also, approximately 1,100 megawatts of owned generating capacity in Asia went into commercial operation in late 1999.
In 1998, Southern Energy's revenues declined because its energy trading and marketing operations -- $2.0 billion in 1997 -- were deconsolidated as of 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 1999 and 1998. Southern Energy's revenues in 1998 of $1.9 billion increased by $48 million compared with comparable revenues in 1997 that exclude energy trading and marketing. This increase resulted primarily from operations of assets obtained in domestic acquisitions.
The decline in 1998 operating expenses 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. Operating expenses and interest charges increased in 1999 as a result of acquisitions and new facilities being placed into service.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
Effects of Inflation
Southern Company's traditional business of the integrated Southeast utilities is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on Southern Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company's future earnings depends on numerous factors. The two major factors are the growth of Southern Energy's operations and the ability of the integrated Southeast utilities to achieve energy sales growth in a less regulated, more competitive environment.
The traditional business or the five Southeast utilities currently operate as vertically integrated companies providing electricity to customers within the traditional service area of the southeastern United States. Prices for electricity provided to retail customers are set by state public service commissions under cost-based regulatory principles. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on earned return on equity. See Note 3 to the financial statements for additional information about these and other regulatory matters.
Future earnings for the traditional business in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new short and long-term contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the traditional service area.
The electric utility industry in the United States is 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's integrated utilities are aggressively working to maintain and expand their 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 continues to 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 a company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on financial condition and results of operations.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if Southern Company's integrated Southeast utilities do not remain low-cost producers and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
To adapt to a less regulated, more competitive environment, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, acquisitions involving other utility or non-utility businesses or properties, internal restructuring, disposition of certain assets, or some combination thereof. Furthermore, Southern Company may engage in other new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations and financial condition of Southern Company.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. To facilitate the development of RTOs, the FERC will convene regional conferences for utilities, customers, and other members of the public to discuss the formation of RTOs. In addition to participating in the regional conferences, utilities owning transmission systems, including Southern Company, are required to make a filing by October 15, 2000. The filing must contain either a proposal for RTO participation or a description of the efforts made to participate in an RTO, the reasons for non-participation, any obstacles to participation, and any plans for further work toward participation. The RTOs that are proposed in the filings should be operational by December 15, 2001. Southern Company is evaluating this issue and formulating its response. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators 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 trading and marketing, distribution, and stand-alone generation. As the energy marketplace evolves, Southern Energy continues to position the company as a major competitor. At December 31, 1999, Southern Energy's total assets were $13.9 billion, and it had ownership or control of over 14,000 megawatts of generating capacity. It has another 5,000 megawatts under construction or advanced development.
In 1999, Southern Energy refined its business strategy to focus on a few key geographic regions of the world. Its Asian subsidiary will focus primarily on China, India, and the Philippines, while also pursuing opportunities in more developed countries such as Australia and Singapore. In Europe, Southern Energy will concentrate efforts in the countries that make up the North-South corridor of continental Europe -- Scandinavia, Italy, Switzerland, Germany, the Netherlands, and select countries in Eastern Europe. In South America, the company is in the process of exiting Argentina and Chile and is reviewing whether or not it will pursue additional opportunities in Brazil. In North America, the company will target its efforts on four U.S. regions -- the Northeast, the Midwest, Texas/Louisiana, and California/Desert Southwest -- and also will pursue opportunities in Canada.
In the United States, Southern Energy plans to acquire, build, or gain access to some 20,000 megawatts of generating capacity over the next several years in order to ensure its success in the evolving competitive wholesale energy supply business. Currently, Southern Energy owns or controls approximately 8,500 megawatts of capacity in the four targeted regions, with an additional 4,100 megawatts under construction or advanced development. All of these assets will be closely linked with Southern Energy's energy trading and marketing business, Southern Company Energy Marketing (SCEM).
In 1998, Southern Energy and Vastar completed the combination of their energy trading and marketing activities to form a joint venture, SCEM. SCEM has the rights to market virtually all of Vastar's natural gas production over a period of 10 years. Southern Energy's current ownership interest in SCEM is 60 percent. On July 1, 2001, this ownership interest will automatically increase to 75 percent. Southern Energy has the right -- exercisable during fiscal year 2002 -- to acquire an additional 5 percent interest from Vastar for $80 million. Also, Vastar has the right -- exercisable in the period from December 1, 2002 through January 2, 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
Southern Company has filed with the Securities and Exchange Commission (SEC) a request to invest up to nearly $6 billion in Southern Energy's domestic and international business. The current SEC authority is $4.1 billion, of which $2.7 billion has been invested as of December 31, 1999.
Southern Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters."
The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry -- including Southern Company's -- regarding the recognition, measurement, and classification in the financial statements of decommissioning costs for nuclear generating facilities. In response to these questions, the Financial Accounting Standards Board (FASB) 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 integrated Southeast utilities are subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of a company's operations is no longer subject to these provisions, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by January 2001. 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.
Year 2000 Challenge
The work undertaken by Southern Company subsidiaries to prepare critical computer systems and other date sensitive devices to function correctly in the Year 2000 was successful. There were no material incidents reported and no disruption of electric service within the service area of the traditional business. There were no reports of significant events regarding third parties that impacted revenues or expenses.
For the traditional business, original projected total costs for Year 2000 readiness were approximately $91 million. Final projected costs are $94 million of which $3 million is projected to be spent in 2000 and $6 million was billed to non-affiliated companies. These costs include labor necessary to identify, test, and renovate affected devices and systems, and costs for reporting requirements to state and federal agencies. From its inception through December 31, 1999, the Year 2000 program costs, recognized primarily as expense, amounted to $85 million based on Southern Company's ownership interest.
Also, Southern Energy experienced no material incidents or disruption of electric service for its domestic and international operations. In addition to the traditional business costs, Southern Energy's final costs for Year 2000 readiness were approximately $17 million -- based on their ownership interest. Southern Energy's original projected costs were $24 million.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
FINANCIAL CONDITION
Overview
Southern Company's financial condition continues to remain strong. In 1999, the integrated Southeast utilities' earnings were at the high end of their allowed range of return on equity, and Southern Energy reported strong earnings growth in 1999. These factors drove the record consolidated net income of $1.3 billion in 1999. Consolidated net income -- excluding non-recurring charges -- in 1999 increased $78 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 down to 50 percent. The quarterly dividend declared in January 2000 continued to be 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. This policy supports Southern Company's strategic goal to become the best investment in the electric utility business.
Gross property additions to utility plant were $2.6 billion in 1999. The majority of funds needed for gross property additions since 1996 has been provided from operating activities. Southern Energy acquired $1.3 billion of generating assets in 1999 and sold the supply system of South Western Electricity -- Southern Energy owned 49 percent -- for $256 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 valuation 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 $27 million at December 31, 1999. Based on the company's overall interest rate exposure at December 31, 1999, 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. To hedge its net investment in these countries, 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. As a result of these swaps, a 10 percent 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, Chile, Trinidad and Tobago, 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
Also, the company has currency exposure related to its investment in Companhia Energetica de Minas Gerais (CEMIG) which has not been hedged. Revenues at CEMIG and dividends from CEMIG are denominated in Brazilian reals; however, a significant portion of debt incurred to finance CEMIG is required to be repaid in other currencies. The devaluation of the real in January 1999 resulted in a net reduction in other comprehensive income of $83 million.
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, natural gas, and energy trading business in North America and Europe. The North American trading business 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, 1999, outstanding guarantees related to the estimated fair value of net contractual commitments were approximately $146 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 were $12.0 billion and $11.9 billion for 1999, respectively; and $9.2 billion and $9.1 billion for 1998, respectively.
In 1999, Southern Energy created a European trading operation in Amsterdam. The business provides risk management services associated with the energy industry to its customers in the European market.
To estimate and manage the market risk of its trading and marketing portfolios, the trading businesses employ 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 5 days to 3 months, 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 VAR analysis of the overall commodity price risk exposure of the trading businesses at December 31, 1999, management does not anticipate a materially adverse effect on the company's consolidated financial statements as a result of market fluctuations.
Due to cost-based rate regulations, the integrated Southeast utilities have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the companies enter into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1999, 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."
Capital Structure
Southern Company's ratio of common equity to total capitalization -- including short-term debt -- was 32.7 percent in 1999, compared with 37.4 percent in 1998, and 38.6 percent in 1997.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
During 1999, the integrated Southeast utilities sold, through public authorities, $349 million of pollution control revenue bonds. In addition, capital and preferred securities of $250 million were issued in 1999. The companies continued to reduce financing costs by retiring higher-cost bonds and preferred stock. Retirements of bonds, including maturities, totaled $1.2 billion during 1999, $1.7 billion during 1998, and $507 million during 1997. As a result, the composite interest rate on long-term debt decreased from 6.9 percent at December 31, 1996 to 6.5 percent at December 31, 1999. Retirements of preferred stock totaled $86 million during 1999, $239 million during 1998, and $660 million during 1997.
In April 1999, Southern Company announced the repurchase of up to 50 million shares of its common stock over a two-year period through open market or privately negotiated transactions. The program did not establish a target stock price or timetable for specific repurchases. Under this program, 32.8 million shares were repurchased through December 31, 1999. Funding for the program was provided from Southern Company's commercial paper program. At the close of 1999, the company's common stock market value was 23 1/2 per share, compared with book value of $13.82 per share. The market-to-book value ratio was 170 percent at the end of 1999, compared with 207 percent at year-end 1998, and 186 percent at year-end 1997.
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $3.0 billion for 2000, $3.8 billion for 2001, and $3.9 billion for 2002. 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 integrated Southeast utilities have approximately 5,200 megawatts of combustion turbine generating capacity scheduled to be placed in service by 2002. Approximately 1,400 megawatts of this new capacity will be dedicated to the wholesale market. Southern Energy has approximately 1,000 megawatts of owned capacity under construction. Significant construction of transmission and distribution facilities and upgrading of generating plants will be continuing for the traditional business in the Southeast.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.1 billion will be required by the end of 2002 for present improvement fund requirements and maturities of long-term debt. Also, the subsidiaries will continue to retire higher-cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit.
Environmental Matters
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
In November 1990, the Clean Air Act 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
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 nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $300 million.
For Phase II sulfur dioxide compliance, Southern Company currently uses emission allowances and increased fuel switching. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment requirements increased total estimated construction expenditures by approximately $105 million.
The States of Georgia and Alabama have proposed or drafted rules to address one-hour ozone non-attainment in the Atlanta and Birmingham areas. Additional nitrogen oxide emission controls will be required on certain generating plants by May 1, 2003. It is expected that seven generating plants will be affected in the Atlanta area and two plants in the Birmingham area. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $850 million.
A significant portion of costs related to the acid rain and ozone nonattainment 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 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 reduction rule to the states for implementation. The final rule affects 22 states, including Alabama and Georgia. The EPA's July 1997 standards and the September 1998 rule are being challenged in the courts by several states and industry groups. Implementation of the final state rules for these three initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: additional controls for hazardous air pollutant emissions; control strategies to reduce regional haze; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations.
Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the subsidiaries could incur substantial costs to clean up properties. The subsidiaries conduct studies to determine the extent of any required cleanup costs and have recognized in their respective financial statements costs to clean up known sites. These costs for Southern Company amounted to $4 million in 1999, $6 million in 1998, and $4 million in 1997. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1999 Annual Report
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 2000 -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. Equity capital can be provided from any combination of public offerings, private placements, or the company's stock plans.
The integrated Southeast utilities plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from internal sources. However, the type and timing of any financings -- if needed -- will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt and trust preferred securities.
To meet short-term cash needs and contingencies, Southern Company had at the beginning of 2000 approximately $466 million of cash and cash equivalents and $5.7 billion of unused credit arrangements with banks.
Cautionary Statement Regarding Forward-Looking Information
Southern Company's 1999 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 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; 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 Southern Energy 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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NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 1999 Annual Report
1. Summary of Significant Accounting Policies
General
Southern Company is the parent company of five integrated Southeast utilities, a system service company, Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), and other direct and indirect subsidiaries. The integrated Southeast utilities -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four states. Contracts among the integrated Southeast utilities -- related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power --are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Southern Energy businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The integrated Southeast utilities 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. The equity method is used for subsidiaries in which the company has significant influence but does not control. 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 integrated Southeast utilities are subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Consolidated Balance Sheets at December 31 relate to the following:
1999 1998 - --------------------------------------------------------------- (in millions) Deferred income tax charges $ 987 $1,036 Premium on reacquired debt 217 294 Department of Energy assessments 52 57 Vacation pay 87 81 Postretirement benefits 33 36 Deferred income tax credits (640) (715) Storm damage reserves (29) (24) Other, net 144 162 - --------------------------------------------------------------- Total $ 851 $ 927 ===============================================================
In the event that a portion of a company's operations is no longer subject to the provisions of FASB Statement No. 71, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
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NOTES (continued) Southern Company and Subsidiary Companies 1999 Annual Report
Revenues and Fuel Costs
Revenues are accrued for service rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. Electric rates for the integrated Southeast utilities include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current regulated rates.
Southern Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $137 million in 1999, $133 million in 1998, and $144 million in 1997. Alabama Power and Georgia Power have contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in January 1998 as required by the contracts, and the companies are pursuing legal remedies against the government for breach of contract. 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. Activities for adding dry cask storage capacity and for potentially increasing spent fuel pool rack capacity at Plant Hatch during 2000 are in progress. Planning for additional on-site spent fuel storage capacity at Plant Farley is also in progress, with the intent to place additional on-site spent fuel storage capacity in operation as early as 2005. In addition, through Southern Nuclear, Alabama Power and Georgia Power are members of Private Fuel Storage, LLC, a joint utility effort to develop a private spent fuel storage facility for temporary storage of spent nuclear fuel. This facility is planned to begin operation as early as the year 2003.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. Alabama Power and Georgia Power -- based on its ownership interests -- estimate their respective remaining liability at December 31, 1999, under this law to be approximately $28 million and $21 million. These obligations are recorded in the Consolidated Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.5 percent in 1999 and 3.4 percent in 1998 and 1997. 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 $314 million in 1998 and $159 million in 1997. Georgia Power did not record any additional depreciation in 1999. 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
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NOTES (continued) Southern Company and Subsidiary Companies 1999 Annual Report
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 of December 31, 1999, 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. Rates used in the assumptions were approved by the respective public service commissions.
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the respective state public service commissions. The amount expensed in 1999 and fund balances were as follows:
Plant Plant Plant Farley Hatch Vogtle - --------------------------------------------------------------- (in millions) Amount expensed in 1999 $18 $17 $9 Accumulated provisions: External trust funds, at fair value $287 $222 $149 Internal reserves 40 22 12 - --------------------------------------------------------------- Total $327 $244 $161 ===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site study. Effective January 1, 1999, the Georgia Public Service Commission (GPSC)increased Georgia Power's annual provision for decommissioning expenses to $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. Alabama Power and Georgia Power expect their respective state public service commissions to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
Income Taxes
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs, and
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replacement of minor items of property is charged to maintenance expense. The cost of replacements of property -- exclusive of minor items of property -- is capitalized.
Property Rights
Property rights primarily consist of leasehold interests in Southern Energy's Asian power generation facilities that are developed under build, operate, and transfer agreements with the government-owned utility. These construction costs for Southern Energy are initially recorded as construction work in progress, and - -- after completion -- they are recorded as leasehold interests. These costs are amortized over the period -- ranging from 12 to 29 years -- that the facility is operated before transfer to the government-owned utility.
Goodwill and Other Intangible Assets
Goodwill, which represents the excess of cost over the fair value of assets of businesses acquired, is amortized on a straight-line basis over periods from 30 to 40 years. Other intangible assets are amortized on a straight-line basis over periods from 15 to 30 years.
Leveraged Leases
Southern Energy has several leveraged lease agreements -- ranging from 21 to 30 years -- that primarily relate to international energy generation, distribution, and transportation assets. The investment income earned from these leveraged leases is immaterial for all periods presented.
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets -- including goodwill and identifiable intangibles -- when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to their estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is reevaluated when circumstances or events change.
Cash and Cash Equivalents
For purposes of the consolidated financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Foreign Currency Translation
Assets and liabilities of Southern Energy'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. Gains and losses on foreign currency transactions are not material for all periods presented.
Comprehensive Income
Comprehensive income -- consisting of net income and foreign currency translation adjustments net of taxes -- is presented in the consolidated financial statements. The objective of the statement is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners.
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NOTES (continued) Southern Company and Subsidiary Companies 1999 Annual Report
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 of the hedged item when the 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 Energy's international operations are exposed to the effects of foreign currency exchange rate fluctuations. To protect against this exposure, currency swaps are used to hedge the 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. Non-trading hedging activities are classified in the same category as the item hedged in the company's cash flow statement.
Non-trading financial derivative instruments held at December 31, 1999, were as follows:
Year of Unrecognized Maturity or Notional Gain Type Termination Amount (Loss) - ------------------------------- -------------------------- (in millions) Interest rate swaps: 2000-2012 $1,910 $(3) 2001-2012 (pound)600 $(49) 2002-2007 DM691 $(5) Cross currency swaps 2001-2007 (pound)414 $(11) Cross currency swaption 2003 DM435 $11 - ----------------------------------------------------------------- (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.
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, 1999 $12,226 $11,557 At December 31, 1998 11,777 11,626 Capital and preferred securities: At December 31, 1999 2,327 2,015 At December 31, 1998 2,179 2,288 - --------------------------------------------------------------
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
During 1999, Southern Energy created an energy trading company in Amsterdam, which provides risk management services associated with the energy industry to its customers in the European market. These services are provided primarily through a variety of exchange-traded energy contracts including forward contracts, futures contracts, option contracts, and financial swap agreements. These contractual commitments, which represent risk management assets and liabilities, are accounted for using the mark-to-market method of accounting. Accordingly, they are reflected at fair value, net of future delivery costs, in the Consolidated Balance Sheets.
Net unrealized gains from risk management services are immaterial at December 31, 1999. The volumetric weighted average maturity of the contractual commitments was 1.35 years. The net notional amount of the risk management assets and liabilities at December 31, 1999 was 5.3 billion kilowatt-hours. The notional amount is indicative only of the volume of activity and not of the amount exchanged by the parties to the financial instruments. Consequently,
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these amounts are not a measure of market risk. The averages for 1999 were based on month-end balances. The fair value of these assets and liabilities at December 31, 1999 was $1 million and $5 million, respectively.
The Amsterdam trading operations involve elements of credit risk. The trading operation has attempted to mitigate this risk by establishing controls to determine and monitor the creditworthiness of counterparties. The company monitors credit risk on both an individual and group counterparty basis. Accordingly, the company does not anticipate any material impact to its financial position or results of operations as a result of counterparty nonperformance.
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 integrated Southeast utilities fund trusts to the extent required by their respective regulatory commissions. The measurement date for plan assets and obligations 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 ------------------- 1999 1998 - -------------------------------------------------------------- (in millions) Balance at beginning of year $4,170 $3,701 Service cost 111 99 Interest cost 265 273 Benefits paid (213) (201) Actuarial (gain) loss (251) 298 - -------------------------------------------------------------- Balance at end of year $4,082 $4,170 ==============================================================
Plan Assets ----------------- 1999 1998 - -------------------------------------------------------------- (in millions) Balance at beginning of year $5,978 $5,931 Actual return on plan assets 1,008 223 Employer contributions - 4 Benefits paid (308) (180) - -------------------------------------------------------------- Balance at end of year $6,678 $5,978 ==============================================================
The accrued pension costs recognized in the Consolidated Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in millions) Funded status $ 2,596 $ 1,808 Unrecognized transition obligation (76) (89) Unrecognized prior service cost 149 119 Unrecognized net gain (2,079) (1,347) - --------------------------------------------------------------- Prepaid asset recognized in the Consolidated Balance Sheets $ 590 $ 491 ===============================================================
Components of the pension plans' net periodic cost were as follows:
1999 1998 1997 - --------------------------------------------------------------- (in millions) Service cost $ 111 $ 99 $ 94 Interest cost 265 273 271 Expected return on plan assets (451) (425) (394) Recognized net gain (42) (47) (42) Net amortization 2 (9) (9) - --------------------------------------------------------------- Net pension cost (income) $(115) $(109) $ (80) ===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations -------------------- 1999 1998 - --------------------------------------------------------------- (in millions) Balance at beginning of year $1,037 $ 935 Service cost 21 18 Interest cost 69 69 Benefits paid (36) (35) Actuarial (gain) loss (95) 50 - ---------------------------------------------------------------- Balance at end of year $ 996 $1,037 ================================================================
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Plan Assets ------------------ 1999 1998 - --------------------------------------------------------------- (in millions) Balance at beginning of year $336 $294 Actual return on plan assets 36 8 Employer contributions 60 69 Benefits paid (37) (35) - --------------------------------------------------------------- Balance at end of year $395 $336 ===============================================================
The accrued postretirement costs recognized in the Consolidated Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in millions) Funded status $(601) $(701) Unrecognized transition obligation 203 219 Unrecognized prior service cost 1 - Unrecognized net loss (gain) 11 117 Fourth quarter contributions 25 30 - --------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $(361) $(335) ===============================================================
Components of the postretirement plans' net periodic cost were as follows:
1999 1998 1997 - -------------------------------------------------------------- (in millions) Service cost $ 21 $ 18 $ 18 Interest cost 69 69 66 Expected return on plan assets (26) (21) (18) Recognized net gain 2 2 3 Net amortization 15 14 17 - -------------------------------------------------------------- Net postretirement cost $ 81 $ 82 $ 86 ==============================================================
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits were:
1999 1998 - --------------------------------------------------------------- Discount 7.50% 6.75% Annual salary increase 5.00 4.25 Long-term return on plan assets 8.50 8.50 - ---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 7.74 percent for 1999, decreasing gradually to 5.50 percent through the year 2005, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 1999 as follows:
1 Percent 1 Percent Increase Decrease - ---------------------------------------------------------------- (in millions) Benefit obligation $73 $(62) Service and interest costs 6 (5) - ----------------------------------------------------------------
Work Force Reduction Programs
Southern Company has incurred additional costs for work force reduction programs. The costs related to these programs were $30 million, $32 million, and $50 million for the years 1999, 1998, and 1997, respectively. In addition, certain costs of these programs were deferred and are being amortized in accordance with regulatory treatment.
3. CONTINGENCIES AND REGULATORY MATTERS
Alabama Power Lake Martin 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. Alabama Power has appealed 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.
Additional actions have been filed by other land owners in the same subdivision on Lake Martin against the same defendants, including Alabama Power. The plaintiffs assert substantially the same allegations as in the current proceeding being appealed. The final outcome of these actions cannot now be determined.
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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, 1999, 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.
Environmental Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day.
The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violations are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place.
An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
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. As a result of the bankruptcy filing, the investment in MESC was deconsolidated. 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 was in response to Kimberly-Clark Tissue Company's (Kimberly-Clark) announcement in May 1998 of plans to close its pulp mill, effective September 1, 1999. The pulp mill had historically provided 50 percent of MESC's revenues.
As a result of settlement discussions with Kimberly-Clark and MESC's bondholders, Southern Company recorded in September 1999 an after-tax write down of $69 million, primarily representing Southern Company's investment in MESC. At December 31, 1999, MESC had total assets of $395 million and senior debt outstanding of $193 million of first mortgage bonds and $73 million related to tax-exempt bonds. In connection with MESC's bond financings, Southern Company provided certain limited guarantees, in lieu of funding debt service and maintenance reserve accounts with cash. As of December 31, 1999, Southern Company had paid $38 million pursuant to the guarantees. Southern Company continues to have guarantees outstanding of certain potential environmental and other obligations of MESC that represent a maximum contingent liability of $21 million at December 31, 1999.
MESC, an unofficial committee of its bondholders, and Kimberly-Clark have reached a tentative agreement to settle disputes arising from the shutdown of Kimberly-Clark's pulp mill in Mobile, Alabama, and to reconfigure energy services at the site. MESC has reached a separate agreement with Southern Energy to develop and operate a 165-megawatt cogeneration facility at the site, including providing a combustion turbine for such facility. The bankruptcy court approved both agreements.
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The finalization of the proposed settlement between MESC and Kimberly-Clark requires further agreements to be negotiated between the parties and certain other conditions to be met, including having a plan of reorganization for MESC be approved by the bankruptcy court and become effective by no later than October 30, 2000. If these conditions, as well as others set out in the settlement agreement filed with the bankruptcy court, are not met, then the proposed settlement would no longer be effective. The final outcome of this matter cannot now be determined.
Southern Energy Brazilian Investment
In September 1999, a Brazilian appellate court granted a temporary injunction that suspended the effectiveness of a shareholders' agreement for Companhia Energetica de Minas Gerais (CEMIG). This ruling suspends the shareholders' agreement -- including Southern Energy's super majority voting rights -- while the action to determine the validity of the agreement is litigated in the lower court. Southern Energy intends to pursue its legal rights in this matter and to have all of its rights restored regarding CEMIG. Southern Energy does not anticipate that this temporary suspension of the shareholders' agreement will have a significant effect on its financial condition or results of operation.
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.
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. Alabama Power did not record any additional amounts in 1999 or 1997.
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 the 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 were decreased by $262 million effective January 1, 1999, and by an additional $24 million effective January 1, 2000. In addition, the order provided for $85 million annually to be applied to accelerated amortization or depreciation of assets, and up to an additional $50 million annually in 2000 and 2001 of any earnings above the 12.5 percent return. In 1999, Georgia Power -- in accordance with the rate order -- recorded $85 million of additional amortization of premium on reacquired debt.
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Two-thirds of any additional earnings above the 12.5 percent return in any year will be applied to rate reductions and the remaining one-third retained by Georgia Power. In 1999, Georgia Power's return was above 12.5 percent, and accordingly, it recorded $79 million as an estimate of revenues to be refunded to customers in 2000. 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 $3.0 billion in 2000, $3.8 billion in 2001, and $3.9 billion in 2002. 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, 1999, significant purchase commitments were outstanding in connection with the construction program. The integrated Southeast utilities have approximately 5,200 megawatts of combustion turbine generating capacity scheduled to be placed in service by 2002. Southern Energy has under construction approximately 1,000 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. FINANCING AND COMMITMENTS
Financing
The amount and timing of additional equity capital to be raised in 2000 -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. Equity capital may be provided from any combination of public offerings, private placements, or the company's stock plans.
The integrated Southeast utilities' 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 2000, unused credit arrangements with banks totaled $5.7 billion, of which $3.1 billion expires during 2000, $1.1 billion during 2001 and 2002, and $1.5 billion during 2003 and 2004. The following table outlines the credit arrangements by company:
Amount of Credit ------------------------------------- Expires -------------------- 2001 & Company Total Unused 2000 beyond - -------- --------------------------------------- (in millions) Alabama Power $ 907 $ 907 $ 517 $ 390 Georgia Power 1,252 1,252 752 500 Gulf Power 103 103 103 - Mississippi Power 104 104 104 - Savannah Electric 61 26 26 - Southern Company 2,000 2,000 1,000 1,000 Southern Energy 3,021 1,256 574 682 Other 60 51 51 - - -------------------------------------------------------------- Total $7,508 $5,699 $3,127 $2,572 ==============================================================
Approximately $2.5 billion of the credit facilities allows for term loans ranging from one to three years. Most of the agreements include stated borrowing rates but also allow for competitive bid loans.
All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. These balances are not legally restricted from withdrawal. Of the total $5.7 billion in unused credit, $1.85 billion, $1.0 billion, $800 million, and $780 million are syndicated credit arrangements of Southern Company, Georgia Power, Southern Energy, and Alabama Power, respectively. These facilities also require the payment of agent fees.
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A portion of the $5.7 billion unused credit with banks is allocated to provide liquidity support to the companies' variable rate pollution control bonds. The amount of variable rate pollution control bonds requiring liquidity support as of December 31, 1999, was $674 million.
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.
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, 1999, were as follows:
Purchased Year Fuel Power - ----- ------------------------ (in millions) 2000 $1,629 $ 81 2001 1,351 81 2002 1,153 97 2003 1,012 99 2004 872 95 2005 and thereafter 3,429 1,006 - --------------------------------------------------------------- Total commitments $9,446 $1,459 ===============================================================
Operating Leases
Southern Company has operating lease agreements with various terms and expiration dates. These expenses totaled $67 million, $56 million, and $36 million for 1999, 1998, and 1997, respectively. At December 31, 1999, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts - ---- ------------ (in millions) 2000 $ 64 2001 83 2002 89 2003 82 2004 82 2005 and thereafter 526 - ------------------------------------------------------------------ Total minimum payments $926 ==================================================================
Long-Term Service Agreements
Southern Energy has entered into several long-term service agreements for the maintenance and repair of its combustion turbine or combined cycle generating plants. These agreements may be terminated in the event a planned construction project is canceled. At December 31, 1999, the annual amounts committed are as follows:
Year Amounts - ---- --------------- (in millions) 2000 $ 3 2001 8 2002 28 2003 51 2004 62 2005 and thereafter 591 - ---------------------------------------------------------------- Total minimum payments $743 ================================================================
Energy Trading and Marketing Commitments
In 1998, Southern Energy and Vastar Resources (Vastar) completed the combination of their energy trading and marketing activities to form a joint venture, Southern Company Energy Marketing (SCEM). SCEM buys and sells physical and financial energy commodities and financial instruments and provides energy-related products and services. SCEM's gross revenues and cost of sales for 1999 were $12.0 billion and $11.9 billion, respectively.
Southern Energy's current ownership interest in SCEM is 60 percent. The equity method of accounting is used because of Vastar's significant
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participation rights. On July 1, 2001, this ownership interest will automatically increase to 75 percent. Southern Energy has the right -- exercisable during fiscal year 2002 -- to acquire an additional 5 percent interest from Vastar for $80 million. Also, Vastar has the right -- exercisable in the period from December 1, 2002 through January 2, 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.
Southern Company and Vastar have separately made guarantees to certain counterparties regarding performance of contractual commitments by SCEM. Southern Company and Vastar have agreed to indemnify each other against losses under such guarantees in proportion to their respective ownership shares of SCEM. At December 31, 1999, outstanding guarantees related to the estimated fair value of net contractual commitments were approximately $146 million. Based upon 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.
Southern Energy has guaranteed certain minimum annual cash distributions, subject to exclusions, payable by SCEM to Vastar. For 1999, this distribution, after adjustments, was $17 million. These distributions before any adjustments total $85 million for the period 2000-2002.
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. JOINT OWNERSHIP AGREEMENTS
Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities jointly with Alabama Electric Cooperative, Inc.
Georgia Power owns undivided interests in plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with OPC, the Municipal Electric Authority of Georgia, the city of Dalton, Georgia, Florida Power &Light Company (FP&L), and Jacksonville Electric Authority (JEA). In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain project and with Florida Power Corporation (FPC) for a combustion turbine unit at Intercession City, Florida.
At December 31, 1999, 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% $3,297 $1,630 Plant Hatch (nuclear) 50.1 857 604 Plant Miller (coal) Units 1 and 2 91.8 740 297 Plant Scherer (coal) Units 1 and 2 8.4 112 51 Plant Wansley (coal) 53.5 299 145 Rocky Mountain (pumped storage) 25.4 169 66 Intercession City (combustion turbine) 33.3 11 * - --------------------------------------------------------------- *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 integrated Southeast utilities 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
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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 $174 million in 1999, $196 million in 1998, and $203 million in 1997.
Unit power from specific generating plants is currently being sold to FP&L, FPC, JEA, and the city of Tallahassee, Florida. Under these agreements, approximately 1,600 megawatts of capacity is scheduled to be sold in 2000. 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 2000 with a minimum of three years notice -- until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1999, the tax-related regulatory assets and liabilities were $987 million and $640 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:
1999 1998 1997 - -------------------------------------------------------------- (in millions) Total provision for income taxes: Federal -- Current $ 486 $ 451 $ 547 Deferred -- current year 186 195 188 -- reversal of prior years (145) (208) (160) - -------------------------------------------------------------- 527 438 575 - -------------------------------------------------------------- State -- Current 85 106 104 Deferred -- current year 16 28 15 -- reversal of prior years (10) (31) (19) - -------------------------------------------------------------- 91 103 100 - -------------------------------------------------------------- International 108 8 164 - -------------------------------------------------------------- Total $ 726 $ 549 $ 839 ==============================================================
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:
1999 1998 - -------------------------------------------------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $3,439 $3,315 Property basis differences 1,516 1,667 Other 585 403 - -------------------------------------------------------------- Total 5,540 5,385 - -------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 102 104 Other property basis differences 221 239 Deferred costs 134 132 Pension and other benefits 90 79 Other 420 293 - --------------------------------------------------------------- Total 967 847 - --------------------------------------------------------------- Net deferred tax liabilities 4,573 4,538 Portion included in current assets, net (68) (57) - --------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheets $4,505 $4,481 ===============================================================
Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Consolidated Statements of Income. Credits amortized in this manner amounted to $35 million in 1999, $38 million in 1998, and $30 million in 1997. At December 31, 1999, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate -- which excludes the effect of minority interests and preferred dividends -- to the effective income tax rate is as follows:
1999 1998 1997 - --------------------------------------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.8 4.1 3.4 Non-deductible book depreciation 1.3 4.1 2.3 Differences in foreign tax rates (5.1) (6.4) - Windfall profits tax - - 8.0 Difference in prior years' deferred and current tax rate (0.9) (1.3) (1.5) Other (0.2) (1.8) (1.9) - --------------------------------------------------------------- Effective income tax rate 32.9% 33.7% 45.3% ===============================================================
Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis.
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The undistributed earnings of foreign subsidiaries aggregated $435 million as of December 31, 1999, and these subsidiaries' earnings are not subject to U.S. income tax until distributed. Of the total undistributed earnings, provisions for U.S. taxes have not been made on $210 million related to earnings that are intended to be reinvested indefinitely.
9. COMMON STOCK
Stock Repurchase Programs
In April 1999, Southern Company's Board of Directors approved the repurchase of up to 50 million shares of Southern Company's common stock over a two-year period through open market or privately negotiated transactions. The program did not establish a target stock price or timetable for specific repurchases. Under this program, 32.8 million shares have been repurchased through December 31, 1999. Funding for the program was provided from Southern Company's commercial paper program.
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 was 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 were repurchased and 2.4 million shares were reissued.
Shares Reserved
At December 31, 1999, a total of 47 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, 1999, 355 current and former employees participated in the Performance Stock Plan. The maximum number of shares of common stock that may be issued under the plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the plan. Stock option activity in 1998 and 1999 for the plan is summarized below:
Shares Average Subject Option Price To Option Per Share - -------------------------------------------------------------- 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 (604,238) 20.21 - -------------------------------------------------------------- Balance at December 31, 1998 6,431,292 22.77 Options granted 2,108,818 26.56 Options canceled (27,995) 25.54 Options exercised (56,708) 19.51 - -------------------------------------------------------------- Balance at December 31, 1999 8,455,407 $23.73 ============================================================== Shares reserved for future grants: At December 31, 1997 38,241,376 At December 31, 1998 36,598,001 At December 31, 1999 34,515,156 - -------------------------------------------------------------- Options exercisable: At December 31, 1998 2,653,591 At December 31, 1999 4,525,349 - --------------------------------------------------------------
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 ------------------------------ 1999 1998 1997 - -------------------------------------------------------------- (in thousands) As reported shares 685,163 696,944 685,033 Effect of options 580 739 201 - -------------------------------------------------------------- Diluted shares 685,743 697,683 685,234 ==============================================================
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Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 1999, consolidated retained earnings included $3.5 billion of undistributed retained earnings of the subsidiaries. Of this amount, $2.0 billion was restricted against the payment by the subsidiary companies of cash dividends on common stock under terms of bond indentures.
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, 1999, capital securities of $950 million and preferred securities of $1.4 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:
1999 1998 - -------------------------------------------------------------- (in millions) Bond improvement fund requirements $ 14 $ 23 Less: Portion to be satisfied by certifying property additions 9 14 - -------------------------------------------------------------- Cash requirements 5 9 First mortgage bond maturities and redemptions 200 868 Other long-term debt maturities 371 563 - -------------------------------------------------------------- Total $576 $1,440 ==============================================================
The first mortgage bond improvement fund requirements amount to 1 percent of each outstanding series of bonds authenticated under the indentures prior to January 1 of each year, other than those issued to collateralize pollution control revenue bonds and other obligations. The requirements may be satisfied by depositing cash or reacquiring bonds, or by pledging additional property equal to 166 2/3 percent of such requirements.
With respect to the collateralized pollution control revenue bonds, the integrated Southeast utilities have authenticated and delivered to trustees a like principal amount of first mortgage bonds as security for obligations under installment sale or loan agreements. The principal and interest on the first mortgage bonds will be payable only in the event of default under the agreements.
Improvement fund requirements and/or serial maturities through 2004 applicable to other long-term debt are as follows: $371 million in 2000; $501 million in 2001; $1.0 billion in 2002; $435 million in 2003; and $1.46 billion in 2004.
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 $9.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. A company could be assessed up to $88 million per incident for each licensed reactor it operates, but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power -- based on its ownership and buyback interests -- is $176 million and $178 million, respectively, per incident, but not more than an aggregate of $20 million per company to be paid for each incident in any one year.
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.
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Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can be insured against increased costs of replacement power in an amount up to $3.5 million per week -- starting 12 weeks after the outage -- for one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the three NEIL policies would be $19 million and $21 million, respectively.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments -- whether generated for liability, property, or replacement power -- may be subject to applicable state premium taxes.
13. ACQUISITIONS AND ASSET SALES
Acquisitions
Southern Energy completed several acquisitions in both 1999 and 1998. In 1999, a $801 million acquisition of 3,065 megawatts of generating capacity from Pacific Gas &Electric in northern California was completed. Additionally, Southern Energy acquired 1,794 megawatts of generating capacity from Orange and Rockland Utilities Inc. and Consolidated Edison Inc. for $476 million. A 9.9 percent interest in Shandong International Power Development Company was purchased in 1999 for $107 million.
Southern Energy paid $537 million in 1998 to Commonwealth Electric for 1,245 megawatts of generating capacity. Also in 1998, Southern Energy acquired a 3.6 percent economic interest in CEMIG -- a Brazilian utility -- for $274 million.
Assets Sold
Southern Energy's significant asset sales in 1999 and 1998 related to its United Kingdom subsidiary South Western Electricity (SWEB). The supply system of SWEB was sold in 1999 for $256 million of which Southern Energy owned 49 percent. The remaining distribution business was renamed Western Power Distribution. In 1998, Southern Energy sold a 26 percent interest in SWEB for $170 million.
Assets for Sale
In December 1998, Southern Energy designed and implemented a plan to dispose of its Argentinean and Chilean investments. As a result, 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, 1999 was $92 million. These assets impacted the Consolidated Statements of Income as follows:
Operating Operating Consolidated Year Revenues Income Net Income - ---- ----------------------------------------- (in millions) 1999 $171 $23 $2 1998 180 37 5 1997 180 37 5
Depreciation expense was suspended beginning January 1999, and the after-tax amount of depreciation recorded in 1998 was $16 million. Southern Energy has been actively pursuing and/or negotiating with potential buyers for its assets in Argentina and Chile. In early 2000, Southern Energy announced an agreement to sell its Argentinean assets substantially at the adjusted carrying value with no material gain or loss expected to be recognized in 2000.
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14. SEGMENT AND RELATED INFORMATION
Southern Company's principal business segment is the five integrated Southeast utilities that provide electric service in four states. The other reportable business segment is Southern Energy, which includes international operations and the competitive energy supply businesses in North America outside the Southeast. Intersegment revenues are not material. Financial data for business segments, products and services, and geographic areas are as follows:
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15. Quarterly Financial Information (Unaudited)
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ALABAMA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Alabama Power Company 1999 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 16, 2000
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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, 1999 and 1998, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-59 through 11-77) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Birmingham, Alabama February 16, 2000
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1999 net income after dividends on preferred stock was $400 million, representing a $23 million (6 percent) increase from the prior year. This improvement is primarily attributable to a decrease in amortization related to premiums paid to reacquire debt pursuant to an Alabama Public Service Commission (APSC) order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details.
In 1998, earnings were $377 million, representing a 0.3 percent increase from the prior year. This increase was due 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 related to premiums paid to reacquire debt pursuant to an APSC order.
The return on average common equity for 1999 was 13.85 percent compared to 13.63 percent in 1998, and 13.76 percent in 1997.
Revenues
Operating revenues for 1999 were $3.4 billion, reflecting a slight decrease from 1998. The following table summarizes the principal factors that have affected operating revenues for the past three years:
Increase (Decrease) From Prior Year ----------------------------------------- 1999 1998 1997 ----------------------------------------- (in thousands) Retail -- Growth and price changes $ 27,893 $ 75,642 $ 33,813 Weather (17,871) 55,282 (22,973) Fuel cost recovery and other 20,418 138,944 31,353 - --------------------------------------------------------------------- Total retail 30,440 269,868 42,193 - --------------------------------------------------------------------- Sales for resale -- Non affiliates (33,596) 17,950 39,354 Affiliates (11,123) (58,233) (54,825) - --------------------------------------------------------------------- Total sales for resale (44,719) (40,283) (15,471) Other operating revenues 13,380 7,677 1,614 - --------------------------------------------------------------------- Total operating revenues $ (899) $237,262 $ 28,336 ===================================================================== Percent change (0.03)% 7.53% 0.91% - ---------------------------------------------------------------------
Retail revenues of $2.8 billion in 1999 increased $30 million (1.1 percent) from the prior year, compared with an increase of $270 million (10.7 percent) in 1998. The primary contributors to the increase in revenues in 1999 were continued growth in the Company's service territory, as well as an increase in fuel revenues. These increases were offset by the effect of milder temperatures in 1999 as compared to 1998.
The $13 million (25.2 percent) increase in other operating revenues in 1999 as compared to 1998 was due primarily to an increase in steam sales in conjunction with the operation of the Company's co-generation facilities. The increase is the result of two new co-generation facilities placed in service in 1999.
Retail revenues in 1998 increased $270 million (10.7 percent) over 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1999 Annual Report
increased fuel revenues. Fuel revenues were higher in 1998 as compared to 1997 due to higher fuel costs and an increase in purchased power. 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.
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. Revenues from long-term power contracts have both a capacity and energy component. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows:
1999 1998 1997 ------------------------------------------- (in millions) Capacity $122 $142 $136 Energy 112 118 135 ------------------------------------------------------------ Total $234 $260 $271 =============================================================
Capacity revenues from non-affiliates decreased 13.9 percent in 1999 compared to the prior year. This decrease is attributable to the lowering of the equity return under formula rate contracts, as well as other adjustments and true-ups related to contractual pricing. Capacity revenues from non-affiliates in 1998 increased 4.1 percent compared to 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 did not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 1999 and the percent change by year were as follows:
KWH Percent Change ------------------------------------------- 1999 1999 1998 1997 ------------------------------------------- (millions)
Residential 15,699 (0.6)% 10.2% (1.8)% Commercial 12,314 3.4 5.1 3.9 Industrial 21,943 1.7 4.2 3.6 Other 201 2.3 8.3 (6.3) ----------- Total retail 50,157 1.4 6.2 1.9 Sales for resale - Non-affiliates 12,438 5.0 (3.2) 29.9 Affiliates 5,032 (15.8) (33.5) (12.6) ----------- Total 67,627 0.5% (0.9)% 3.7% - ------------------------------------------------------------------
The increases in 1999 and 1998 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 2.9 percent annually on average during 2000 through 2004.
Expenses
Total operating expenses of $2.5 billion for 1999 were down $13.4 million or 0.5 percent compared with 1998. This decrease was mainly due to a $15 million decrease in fuel and purchased power costs and a $23 million decrease in maintenance expense, offset by an increase in taxes other than income taxes of $12 million.
Total operating expenses of $2.5 billion for 1998 were up $203 million or 8.8 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.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1999 Annual Report
fuel per net KWH generated were as follows:
---------------------------- 1999 1998 1997 ---------------------------- Total generation (billions of KWHs) 63 63 65 Sources of generation (percent) -- Coal 72 72 72 Nuclear 20 18 20 Hydro 5 8 8 Oil & Gas 3 2 * Average cost of fuel per net KWH generated (cents) -- 1.44 1.54 1.49 - ---------------------------------------------------------------- * Not meaningful because of minimal generation from fuel source.
Total fuel and purchased power costs of $1.1 billion in 1999 decreased $15 million (1 percent), while total energy sales increased 329 million kilowatt hours (0.5 percent) compared with the amounts recorded in 1998. Continued efforts to control energy costs helped lower the average cost of fuel per net kilowatt hour generated in 1999.
Fuel and purchased power costs in 1998 increased $111 million (11 percent) over 1997 due primarily to lower levels of nuclear and hydro generation, which were replaced by the use of peaking units and purchased power.
Purchased power consists primarily of purchases from affiliates in 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.
The 7.5 percent decrease in maintenance expense in 1999 as compared to 1998 is primarily attributable to a decrease in distribution expenses. The 23.8 percent increase in maintenance expenses in 1998 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.
Depreciation and amortization expense increased 2.6 percent in 1999 and 1998. These increases reflect additions to property, plant, and equipment.
Taxes other than income taxes increased $12 million (6.0 percent) in 1999 as compared to 1998. This increase is attributable to increases in real and personal property taxes and public utility license taxes.
Total net interest and other charges decreased $38 million (12.3 percent) in 1999. This decrease results primarily from a decrease in the amortization of premiums on reacquired debt pursuant to an APSC order. Total net interest and other charges increased $55.7 million (22 percent) in 1998 primarily due to an increase in the amortization of premiums on reacquired debt, pursuant to an APSC order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plants with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
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, including the ability of the Company to achieve energy sales growth in 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1999 Annual Report
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, new short and long-term contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's traditional service area.
The electric utility industry in the United States is 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/or 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.
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 continues to 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 and results of operations.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. To facilitate the development of RTOs, the FERC will convene regional conferences for utilities, customers, and other members of the public to discuss the formation of RTOs. In addition to participating in the regional conferences, utilities owning transmission systems, including Southern Company, are required to make a filing by October 15, 2000. The filing must contain either a proposal for RTO participation or a description of the efforts made to participate in an RTO, the reasons for non-participation, any obstacles to participation, and any plans for further work toward participation. The RTOs that are proposed in the filings should be operational by December 15, 2001. The Company is evaluating this issue and formulating its response. The outcome of this matter cannot presently be determined.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1999 Annual Report
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.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by January 1, 2001. 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.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and other date sensitive devices to function correctly in the Year 2000 was successful. There were no material incidents reported and no disruption of electric service within the service area. There were no reports of significant events regarding third parties that impacted revenues or expenses.
For the Company, original projected total costs for Year 2000 readiness, including the Company's share of costs of Southern Nuclear Operating Company, were approximately $36 million; revised projected costs are $33 million. These costs include labor necessary to identify, test, and renovate affected devices and systems, and costs for fulfilling reporting requirements to state and federal agencies. From its inception through December 31, 1999, the Year 2000 program costs, recognized primarily as expense, amounted to $32 million.
Exposure to Market Risk
Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1999, 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, 1999, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1999 Annual Report
FINANCIAL CONDITION
Overview
The Company's financial condition remained stable in 1999. 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 $809 million in 1999. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, principally from earnings and non-cash charges to income such as depreciation and deferred income taxes. The Statements of Cash Flows provide additional details.
Capital Structure
The Company's ratio of common equity to total capitalization -- including short-term debt -- was 42.4 percent in 1999 and 1998, and 44.7 percent in 1997.
During 1999, the Company issued $650 million of senior notes, the proceeds of which were used primarily to redeem first mortgage bonds and repay short-term indebtedness, and the Company redeemed $50 million of preferred stock.
Additionally, in February 1999, Alabama Power Capital Trust III, of which the Company owns all of the common securities, issued $50 million of auction rate mandatorily redeemable preferred securities. See Note 9 to the financial statements for additional information.
Capital Requirements
Capital expenditures are estimated to be $831 million for 2000, $743 million for 2001, and $860 million for 2002. See Note 4 to the financial statements for additional details.
Actual construction costs may vary from estimates because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $100 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
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action against the Company in the U. S. District Court. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued a notice of violation to the Company relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The Company believes that it complied with applicable laws and EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1999 Annual Report
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 integrated Southeast utilities 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 currently uses emission allowances and increased fuel switching, and/or the installation of flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits. Compliance for Phase II increased total estimated construction expenditures in 1999 by approximately $65 million.
The State of Alabama and the EPA are currently evaluating draft plans to reach attainment with the one hour standard for ozone in the Birmingham non-attainment area. Provisions of that plan would require nitrogen oxide reductions at certain Company facilities by May 2003. The Company estimates the capital cost to comply with the plan to be approximately $138 million, all of which remains to be spent.
A significant portion of costs related to the acid rain and ozone non-attainment 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 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 reduction rule to the states for implementation. The final rule affects 22 states including Alabama. The EPA's July 1997 standards and the September 1998 rule are being challenged in the courts by several states and industry groups. Implementation of the final state rules for these three initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: additional controls for hazardous air pollutant emissions and control strategies to reduce regional haze. The impact of any new standards will depend on the development and implementation of applicable regulations.
In addition to rules and pending changes to rules under the Clean Air Act, the Company must comply with other environmental laws and regulations including water discharge permits, solid and hazardous waste disposal, use of materials controlled by the Toxic Substances Control Act, and reporting requirements under the Comprehensive Environmental Response, Compensation, and Liability Act. Under these various requirements and regulations, the Company could incur costs to implement water discharge requirements, clean up properties containing hazardous substances, or replace equipment rendered useless by changing requirements. The exact impact of any requirements would depend on specific regulatory actions and cannot be determined at this time.
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) Alabama Power Company 1999 Annual Report
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. The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, to issue additional first mortgage bonds and preferred stock, 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."
Cautionary Statement Regarding Forward-Looking Information
The Company's 1999 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; 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 Alabama Power Company 1999 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five integrated Southeast utilities, Southern Company Services (SCS), 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 integrated Southeast utilities --Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company-- provide electric service in four states. Contracts among the integrated Southeast utilities - related to jointly-owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Southern Energy businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Alabama Public Service Commission (APSC). The Company follows generally accepted accounting principles (GAAP) and complies with the accounting policies and practices prescribed by its 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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $218 million, $201 million, and $154 million during 1999, 1998, and 1997, respectively.
The Company also has an agreement with Southern Nuclear to operate Plant Farley and provide the following nuclear-related services at cost: general executive and advisory services; general operations, management and technical services; administrative services including procurement, accounting, statistical, and employee relations; and other services with respect to business and operations. Costs for these services amounted to $135 million, $137 million, and $117 million during 1999, 1998, and 1997, respectively.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
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NOTES (continued) Alabama Power Company 1999 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following:
1999 1998 ----------------------- (in millions) Deferred income tax charges $ 330 $ 363 Deferred income tax credits (265) (316) Premium on reacquired debt 84 83 Department of Energy assessments 28 31 Vacation pay 30 28 Natural disaster reserve (19) (19) Other, net 59 51 - ---------------------------------------------------------------- Total $ 247 $ 221 ================================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair values.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Alabama, and to wholesale customers in the southeast. 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 regulated rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continue to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $63 million in 1999, $59 million in 1998, and $68 million in 1997. The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in January 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient storage capacity currently is available to permit operation into 2009 and 2013 at Plant Farley units 1 and 2, respectively. Planning for additional on-site spent fuel storage capacity at Plant Farley is in progress, with the intent to place additional on-site spent fuel storage capacity in operation as early as 2005. In addition, through Southern Nuclear, the Company is a member of Private Fuel Storage, LLC, a joint utility effort to develop a private spent fuel storage facility for temporary storage of spent nuclear fuel. This facility is planned to begin operation as early as the year 2003.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment 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, 1999, under this law to be approximately $28 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 1999 and 1998, and 3.3 percent in 1997. 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
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established external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the APSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs -- based on the most current study for Plant Farley were as follows:
Site study basis (year) 1998
Decommissioning periods: Beginning year 2017 Completion year 2031 ------------------------------------------------------------- (in millions) Site study costs: Radiated structures $ 629 Non-radiated structures 60 ------------------------------------------------------------- Total $ 689 ============================================================= (in millions) Ultimate costs: Radiated structures $ 1,868 Non-radiated structures 178 ------------------------------------------------------------- Total $ 2,046 =============================================================
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making estimates.
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the APSC. The amount expensed in 1999 and fund balances as of December 31, 1999 were:
(in millions) Amount expensed in 1999 $ 18 -------------------------------------------------------------
Accumulated provisions: External trust funds, at fair value $ 287 Internal reserves 40 ------------------------------------------------------------- Total $ 327 =============================================================
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. The Company expects the APSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Allowance For Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rate used to determine the amount of allowance was 8.8 percent in 1999, 9.0 percent in 1998, and 5.8 percent in 1997. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 4.7 percent in 1999, 1.8 percent in 1998, and 0.8 percent in 1997.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other
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benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is capitalized.
Financial Instruments
The Company's 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, 1999 $3,286 $3,045 At December 31, 1998 3,112 3,195 Preferred Securities: At December 31, 1999 347 299 At December 31, 1998 297 307 --------------------------------------------------------------
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. At December 31, 1999, the reserve balance was $19 million.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, pension plans that cover substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for such benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations or to the extent required by the APSC and FERC. The measurement date for plan assets and obligations is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were:
1999 1998 - --------------------------------------------------------------- Discount 7.50% 6.75% Annual salary increase 5.00 4.25 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 --------------------------- 1999 1998 - --------------------------------------------------------------- (in millions) Balance at beginning of year $868 $813 Service cost 23 22 Interest cost 57 59 Benefits paid (51) (51) Actuarial (gain) loss and employee transfers (24) 25 - --------------------------------------------------------------- Balance at end of year $873 $868 ===============================================================
Plan Assets --------------------------- 1999 1998 - --------------------------------------------------------------- (in millions) Balance at beginning of year $1,461 $1,521 Actual return on plan assets 245 9 Benefits paid (51) (51) Employee transfers (8) (18) - --------------------------------------------------------------- Balance at end of year $1,647 $1,461 ===============================================================
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The accrued pension costs recognized in the Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in millions) Funded status $ 774 $ 593 Unrecognized transition obligation (25) (30) Unrecognized prior service cost 36 39 Unrecognized net actuarial gain (571) (433) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 214 $ 169 ===============================================================
Components of the pension plans' net periodic cost were as follows:
1999 1998 1997 - --------------------------------------------------------------- (in millions) Service cost $ 23 $ 22 $ 20 Interest cost 57 59 58 Expected return on plan assets (109) (102) (95) Recognized net actuarial gain (14) (16) (13) Net amortization (2) (2) (2) - --------------------------------------------------------------- Net pension income $ (45) $ (39) $(32) ===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------------- 1999 1998 - --------------------------------------------------------------- (in millions) Balance at beginning of year $278 $252 Service cost 5 5 Interest cost 18 19 Benefits paid (10) (12) Actuarial (gain) loss and employee transfers (27) 14 - --------------------------------------------------------------- Balance at end of year $264 $278 ===============================================================
Plan Assets --------------------------- 1999 1998 - --------------------------------------------------------------- (in millions) Balance at beginning of year $137 $125 Actual return on plan assets 18 4 Employer contributions 16 20 Benefits paid (10) (12) - --------------------------------------------------------------- Balance at end of year $161 $137 ===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in millions) Funded status $(103) $(141) Unrecognized transition obligation 53 57 Unrecognized net actuarial (gain) loss (12) 22 Fourth quarter contributions 8 8 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (54) $ (54) ===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997 - --------------------------------------------------------------- (in millions) Service cost $ 5 $ 5 $ 4 Interest cost 18 18 18 Expected return on plan assets (11) (9) (7) Net amortization 4 4 4 - --------------------------------------------------------------- Net postretirement cost $ 16 $ 18 $ 19 ===============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 7.74 percent for 1999, decreasing gradually to 5.50 percent through the year 2005, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 1999 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $ 17 $ (15) Service and interest costs 1 (1) ===============================================================
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The costs related to these programs were $5.6 million, $19.4 million and $33.0 million for the years 1999, 1998 and 1997, 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 $1.2 million at December 31, 1999.
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3. CONTINGENCIES AND REGULATORY MATTERS
Lake Martin 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. The Company has appealed these judgments 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.
Additional actions have been filed by other landowners in the same subdivision on Lake Martin against the same defendants, including the Company. The plaintiffs assert substantially the same allegations as in the current proceeding being appealed. The final outcome of these actions cannot now be determined.
Environmental Protection Agency Litigation
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action against the Company in the U. S. District Court. The complaint alleges violations of the prevention of significant deterioration and new source review provision of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units beginning at the point of the alleged violations. The EPA concurrently issued a notice of violation to the Company relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
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 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 Company did not record any additional amounts in 1999 or 1997.
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The Company's ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
4. CAPITAL BUDGET
The Company's capital expenditures are currently estimated to total $831 million in 2000, $743 million in 2001, and $860 million in 2002. Some of the more significant items included in the Company's capital budget are as follows:
(i) The Company is replacing all six steam generators at Plant Farley. The estimated remaining costs associated with this project, which will be completed in 2001, amount to $100 million.
(ii) The Company is also constructing and installing 1,075 megawatts of capacity and associated substation facilities at Plant Barry. Half of the capacity is scheduled to go in service in 2000, with the remainder going in service in 2001. The remaining projected expenditures related to these facilities are $181 million.
(iii)Cogeneration facilities, with a capacity of 200 megawatts, are being constructed in Theodore, Alabama, and will go in service in 2001. The estimated remaining costs associated with this project total $81 million.
(iv) The capital budget reflects $472 million related to projected generation capacity scheduled to be placed into service in 2003 and beyond.
In addition to the above items, significant construction will continue related to transmission and distribution facilities and the upgrading of generating plants.
The capital budget is subject to periodic review and revision, and actual capital costs incurred may vary from estimates because of changes in such factors as: business conditions; environmental regulations; nuclear plant 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.
5. FINANCING 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. The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, to issue additional first mortgage bonds and preferred stock, 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 $907 million (including $418 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds). Of these lines, $517 million expire at various times during 2000 and $390 million expire in 2004. In certain cases, such lines require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Because the arrangements are based on an average balance, the
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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, 1999, 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.
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, 1999, were as follows:
Year Commitments - ---- ---------------- (in millions) 2000 $ 715 2001 672 2002 561 2003 469 2004 472 2005 - 2026 2,019 - --------------------------------------------------------------- Total commitments $4,908 ===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $17.8 million in 1999, $5.8 million in 1998, and $3.0 million in 1997. At December 31, 1999, estimated minimum rental commitments for noncancellable operating leases were as follows:
Year Commitments - ---- ----------------- (in millions) 2000 $ 20.0 2001 19.6 2002 19.2 2003 18.8 2004 18.4 2005 - 2017 64.3 - -------------------------------------------------------------- Total minimum payments $160.3 ==============================================================
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 $92 million in 1999, $74 million in 1998 and $73 million in 1997, 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.
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At December 31, 1999, the capitalization of SEGCO consisted of $50 million of equity and $72 million of long-term debt on which the annual interest requirement is $4.3 million. SEGCO paid dividends totaling $4.3 million in 1999, $8.7 million in 1998, and $10.6 million in 1997, of which one-half of each was paid to the Company. SEGCO's net income was $5.4 million, $7.5 million, and $8.5 million for 1999, 1998 and 1997, respectively.
The Company's percentage ownership and investment in jointly-owned generating plants at December 31, 1999, 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 $ 97 $ 45 Plant Miller Units 1 and 2 740 297 ----------------------------------------------------------
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 $122 million in 1999, $142 million in 1998, and $136 million in 1997.
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 1,250 megawatts of capacity are scheduled to be sold through 2000. Thereafter, these sales will remain at that approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after 2000 with a minimum of three years notice -- until the expiration of the contracts in 2010.
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, 1999, $81.5 million of such bonds was held by the escrow agent under the contracts.
8. INCOME TAXES
At December 31, 1999, the tax-related regulatory assets and liabilities were $330 million and $265 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable
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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 income tax provisions are as follows:
1999 1998 1997 -------------------------------- (in millions) Total provision for income taxes: Federal -- Current $194 $123 $197 Deferred -- Current year (6) 59 33 Reversal of prior years 30 13 (44) - ----------------------------------------------------------------- 218 195 186 - ----------------------------------------------------------------- State -- Current 19 16 23 Deferred -- Current year 1 5 1 Reversal of prior years 4 2 (2) - ----------------------------------------------------------------- 24 23 22 - ----------------------------------------------------------------- Total $242 $218 $208 =================================================================
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:
1999 1998 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $ 884 $ 861 Property basis differences 419 435 Fuel cost adjustment 65 29 Premium on reacquired debt 31 29 Pensions 60 50 Other 11 17 - ----------------------------------------------------------------- Total 1,470 1,421 - ----------------------------------------------------------------- Deferred tax assets: Capacity prepayments 24 28 Other deferred costs 25 25 Postretirement benefits 22 20 Unbilled revenue 13 16 Other 63 56 - ----------------------------------------------------------------- Total 147 145 - ----------------------------------------------------------------- Net deferred tax liabilities 1,323 1,276 Portion included in current liabilities, net (83) (73) - ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,240 $1,203 =================================================================
Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $11 million in 1999, 1998, and 1997. At December 31, 1999, 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:
1999 1998 1997 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.4 2.5 2.4 Non-deductible book depreciation 1.6 1.5 1.5 Differences in prior years' deferred and current tax rates (1.3) (1.6) (2.3) Other (0.9) (1.6) (1.9) - --------------------------------------------------------------- Effective income tax rate 36.8% 35.8% 34.7% ===============================================================
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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.
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 Trust III 2/1999 50 Auction 52 2/2029
Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above. In February 1999, Alabama Power Capital Trust III (Trust III), of which the Company owns all of the common securities, issued $50 million of auction rate mandatorily redeemable preferred securities. The distribution rate of these variable securities was 6.42% at January 1, 2000.
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. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.
In 1997, 1998, and 1999 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 2004 are as follows: $0.9 million in 2000, $0.8 million in 2001, $0.9 million in 2002, $0.9 million in 2003 and $1.0 million in 2004.
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:
1999 1998 ------------------------ (in thousands) First mortgage bond maturities and redemptions $100,000 $470,000 Other long-term debt maturities (Note 10) 943 1,209 ------------------------------------------------------------- Total long-term debt due within one year 100,943 471,209 ------------------------------------------------------------- Preferred stock to be redeemed - 50,000 ------------------------------------------------------------- Total $100,943 $521,209 =============================================================
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.
12. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (the Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $9.5 billion for public liability claims
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that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums which could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $88 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $176 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional cost that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can be insured against increased costs of replacement power in an amount up to $3.5 million per week (starting 12 weeks after the outage) for one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the three NEIL policies would be $19 million.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property or replacement power may be subject to applicable state premium taxes.
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, 1999, 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 1999 and 1998 are as follows:
Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock - -------------------- -------------------------------------------- (in millions)
March 1999 $ 714 $162 $ 63 June 1999 823 209 93 September 1999 1,116 388 201 December 1999 733 136 43
March 1998 $ 717 $173 $ 66 June 1998 864 235 95 September 1998 1,058 342 174 December 1998 748 132 42 - -----------------------------------------------------------------
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 1999 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/David M. Ratcliffe David M. Ratcliffe President and Chief Executive Officer
/s/Thomas A. Fanning Thomas A. Fanning Executive Vice President, Treasurer and Chief Financial Officer
February 16, 2000
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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, 1999 and 1998, and the related statements of income, common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-91 through 11-110) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Atlanta, Georgia February 16, 2000
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1999 earnings totaled $541 million, representing a $29 million (5.1 percent) decrease from 1998. This earnings decrease is primarily due to the recognition of interest income in 1998 as a result of the resolution of tax issues with the Internal Revenue Service (IRS). Earnings from normal operations increased due primarily to lower accelerated depreciation under the 1998 Georgia Public Service Commission (GPSC) rate order, sales growth and decreased financing costs, partially offset by retail rate reductions under the new order and lower wholesale revenues. Earnings for 1998 totaled $570 million, representing a $24 million (4.0 percent) decrease from 1997. This earnings decrease resulted primarily from higher operating expenses, accelerated depreciation charges pursuant to a previous GPSC retail accounting order ending December 1998, lower wholesale 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 the effect of the IRS settlement.
Revenues
The following table summarizes the factors impacting operating revenues for the 1997-1999 period:
Increase (Decrease) From Prior Year -------------------------------- 1999 1998 1997 -------------------------------- Retail - (in millions) 1998 GPSC rate order $(262) $ - $ - Revenue subject to refund (79) - - Sales growth 102 174 62 Weather (53) 101 (74) Fuel cost recovery and other 44 45 (33) - -------------------------------------------------------------------- Total retail (248) 320 (45) - -------------------------------------------------------------------- Sales for resale - Non-affiliates (49) (23) 1 Affiliates (5) 43 3 - -------------------------------------------------------------------- Total sales for resale (54) 20 4 - -------------------------------------------------------------------- Other operating revenues 21 13 10 - -------------------------------------------------------------------- Total operating revenues $(281) $ 353 $ (31) ==================================================================== Percent change (5.9)% 8.0% (0.7)% - --------------------------------------------------------------------
Retail revenues of $4.1 billion in 1999 decreased $248 million (5.8 percent) primarily due to retail rate reductions under the 1998 GPSC rate order. Pursuant to the order, in 1999 the Company also recorded $79 million of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity. Refunds will be made to customers in 2000. See Note 3 to the financial statements under "Retail Rate Orders" for additional information. 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.
Fuel revenues generally represent the direct recovery of fuel expense, including the fuel component of purchased energy, and do not affect net income.
Wholesale revenues from sales to non-affiliated utilities decreased in 1999 and 1998 and were as follows:
1999 1998 1997 ------------------------------- (in millions) Outside service area -
Long-term contracts $ 55 $ 51 $ 71 Other sales 74 93 79 Inside service area 81 115 132 - --------------------------------------------------------------- Total $ 210 $ 259 $ 282 ===============================================================
Revenues from long-term contracts outside the service area increased slightly in 1999 due to increased energy sales and decreased in 1998 primarily due to lower capacity charges and decreased energy sales. See Note 7 to the financial statements for further information regarding these sales. Revenues from other sales outside the service area decreased in 1999 and increased in 1998 primarily due to the effect of power marketing activities and were generally offset by a corresponding decrease and increase, respectively, in purchased power from non-affiliates. Wholesale revenues from customers within the service area decreased in 1999 and 1998 primarily due to a decrease in revenues under a power supply agreement with Oglethorpe Power Corporation (OPC).
Revenues from sales to affiliated companies within the Southern electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These transactions do not have a significant impact on earnings.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1999 Annual Report
Other operating revenues increased $21 million (21 percent) primarily due to increased revenues from equipment rentals. In 1998, other operating revenues increased $13 million (14.9 percent) primarily due to increased revenues from the transmission of electricity.
Kilowatt-hour (KWH) sales for 1999 and the percent change by year were as follows:
Percent Change ---------------------------- KWH 1999 1998 1997 --------- ----------------------------- (in billions)
Residential 19.4 (0.4)% 12.6% (3.0)% Commercial 23.7 3.7 8.2 1.5 Industrial 27.3 0.1 2.2 1.9 Other 0.6 1.5 1.0 0.4 -------- Total retail 71.0 1.1 6.9 0.4 -------- Sales for resale - Non-affiliates 5.0 (21.4) (5.2) (13.6) Affiliates 1.8 (11.9) 19.4 44.6 -------- Total sales for resale 6.8 (19.1) (0.3) (6.0) -------- Total sales 77.8 (1.0) 6.0 (0.3) ========
- ------------------------------------------------------------------
Residential sales decreased 0.4 percent in 1999 due to moderate summer temperatures, while commercial sales increased 3.7 percent due to strong regional economic growth. Industrial sales remained fairly constant. 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.
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:
1999 1998 1997 ------------------------- Total generation (billions of KWH) 69.3 69.1 66.5 Sources of generation (percent) -- Coal 75.5 73.3 74.8 Nuclear 21.6 21.6 21.8 Hydro 1.0 2.6 2.7 Oil and gas 1.9 2.5 0.7 Average cost of fuel per net KWH generated (cents) -- 1.34 1.36 1.32 - ---------------------------------------------------------------
Fuel expense increased 0.3 percent in 1999 due to a slight increase in generation, partially offset by a lower average cost of fuel. 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.
Purchased power expense decreased slightly in 1999. Purchased power expense in 1998 increased $70 million (21.9 percent) over the prior year primarily due to higher energy demands and power marketing activities. As discussed earlier, the expense associated with energy purchased for power marketing activities is generally offset by revenue when resold to non-affiliates.
Other operation and maintenance expenses increased 1.6 percent in 1999 primarily due to increased generating plant maintenance, partially offset by a reduction in the charges related to the implementation of a customer service system in 1998, decreased year 2000 readiness costs, and decreased employee benefit provisions. Other operation and maintenance expenses increased 15.5 percent in 1998 primarily due to expenses related to the customer service system discussed above, modification of certain information systems for year 2000 compliance discussed below, an increase in outage costs at generating facilities, and increased line maintenance.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1999 Annual Report
Depreciation and amortization decreased $346 million in 1999 primarily due to higher depreciation charges recognized in 1998 under the prior GPSC accounting order and the completion in 1998 of the amortization of deferred Plant Vogtle costs. Depreciation and amortization increased $121 million in 1998 primarily due to accelerated depreciation of generating plant pursuant to the previous retail accounting order and an increase in plant-in-service. See Note 3 to the financial statements under "Retail Rate Orders" for additional information.
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 in 1998. See Note 3 to the financial statements under "Rocky Mountain Status" for additional information.
Interest income decreased in 1999 primarily due to the 1998 recognition of $73 million in interest income resulting from the resolution of tax issues with the IRS and the State of Georgia. Other, net decreased in 1999 due primarily to increased bad debt expense related to consumer energy efficiency improvement financing.
Financing costs decreased in 1999 and 1998. These changes were primarily due to the refinancing or retirement of securities. The Company refinanced or retired $775 million and $754 million of securities in 1999 and 1998, respectively. Dividends on preferred stock decreased $4 million and $13 million in 1999 and 1998, respectively. Pursuant to the new three-year retail rate order which the Company began operating under on January 1, 1999, the Company recorded $85 million in accelerated amortization of premium on reacquired debt. Other interest charges decreased $12 million in 1999 primarily due to the recognition in 1998 of interest related to tax issues. Distributions on preferred securities of subsidiary companies increased $11 million and $7 million in 1999 and 1998, respectively, primarily due to the issuance of additional mandatorily redeemable preferred securities in 1999 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.
On January 1, 1999, the Company began operating under a new three-year retail rate order. 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 above the 12.5 percent return during the second and third years, to be applied to accelerated amortization or depreciation of assets. Two-thirds of any additional earnings above the 12.5 percent return will be applied to rate reductions, with the remaining one-third retained by the Company. Pursuant to the order, in 1999 the Company recorded $85 million in accelerated amortization of premium on reacquired debt. The Company also recorded $79 million of revenue subject to refund for estimated earnings above 12.5 percent. Refunds will be made to customers in 2000. 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 Orders" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1999 Annual Report
Growth in energy sales is subject to a number of factors which traditionally have included changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, weather, competition, initiatives to increase sales to existing customers, and the rate of economic growth in the Company's service area. Assuming normal weather, retail sales growth from 1999 is projected to be approximately 2.9 percent annually on average during 2000 through 2002.
The Company has entered into two purchase power agreements scheduled to begin after 1999. The first agreement is for five years and will begin in June 2000. The agreement is for approximately 215 megawatts, and capacity payments are estimated to be between $7 million and $8 million each year. The second agreement is for seven years and will begin in June 2002. The agreement is for approximately 310 megawatts during the first three years and approximately 465 megawatts during the remaining four years. Capacity payments are estimated to be between $16 million and $17 million in each of the first three years and then between $23 million and $24 million in each of the last four years of the contract.
The Company is constructing a ten unit, 800 megawatt combustion turbine peaking power plant that will serve the wholesale market. Units one through eight will begin operation in 2000; units nine and ten will begin operation in 2001. The Company also plans to construct a 570 megawatt combined cycle unit that will begin operation in 2002 and will also serve the wholesale market. The Company has entered into wholesale contracts to sell 560 megawatts of the new capacity. The Company is also planning to construct two 568 megawatt combined cycle units at Plant Wansley, to begin operation in 2002. The Company has applied to the GPSC for certification of these units to serve retail customers. Savannah Electric (also a wholly-owned subsidiary of Southern Company) will purchase 200 megawatts of capacity from these units. See Note 4 to the financial statements under "Construction Program" for additional information.
Compliance costs related to current and future environmental laws, regulations, and litigation could affect earnings if such costs are not fully recovered. See "Environmental Issues" for further discussion of these matters.
The electric utility industry in the United States is 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. 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.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. To facilitate the development of RTOs, the FERC will convene regional conferences for utilities, customers, and other members of the public to discuss formation of RTOs. In addition to participating in the regional conferences, utilities owning transmission systems, including the Company, are required to make a filing by October 15, 2000. The filing must contain either a proposal for RTO participation or a description of the efforts made to participate in an RTO, the reasons for non-participation, any obstacles to participation, and any plans for further work toward participation. The RTOs that are proposed in the filings should be operational by December 15, 2001. The Company is evaluating the issue and the outcome cannot now be determined.
The Company continues to compete with other electric suppliers within the state. In Georgia, most new retail customers with at least 900 kilowatts of connected load may choose their electricity supplier. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition across the nation. Among other things, these initiatives allow customers to choose their electricity provider. As these initiatives materialize, the structure of the utility industry could radically change. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While the GPSC has held workshops to discuss retail competition and industry restructuring, there has been no proposed or enacted legislation to date in Georgia. Enactment would require numerous issues to be resolved, including significant ones relating to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1999 Annual Report
transmission pricing and recovery of costs. The GPSC plans to release a report on an initial assessment of the range of potential stranded costs in 2000. The inability of the Company to recover all its costs, including the regulatory assets described in Note 1 to the financial statements, could have a material effect on the financial condition of the Company. The Company is attempting to reduce regulatory assets and other costs through the three-year retail rate order. See Note 3 to the financial statements under "Retail Rate Orders" 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.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and other date sensitive devices to function correctly in the Year 2000 was successful. There were no material incidents reported and no disruption of electric service within the service area. There were no reports of significant events regarding third parties that impacted revenues or expenses.
For the Company, original projected total costs for Year 2000 readiness, including the Company's share of costs of Southern Nuclear Operating Company, were approximately $38 million. These costs include labor necessary to identify, test, and renovate affected devices and systems, and costs for reporting requirements to state and federal agencies. From its inception through December 31, 1999, the Year 2000 program costs, recognized as expense, amounted to $41 million. An additional $2 million is projected to be spent in 2000.
Exposure to Market Risks
Due to cost-based rate regulation, the Company currently has limited exposure to market volatility in interest rates and prices of electricity. See the discussion above for potential changes in industry structure. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1999, 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, 1999, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by January 2001. This statement establishes accounting and reporting standards for derivative instruments - including certain derivative instruments embedded in other contracts - and for
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1999 Annual Report
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.
FINANCIAL CONDITION
Plant Additions
In 1999 gross utility plant additions were $790 million. These additions were primarily related to transmission and distribution facilities, the purchase of nuclear fuel and the construction of additional combustion turbine and combined cycle units. The funds needed for gross property additions are currently provided from operations, short or long-term debt, and from equity from Southern. The Statements of Cash Flows provide additional details.
Financing Activities
In 1999 the Company continued to lower its financing costs by refinancing higher-cost issues. New issues during 1997 through 1999 totaled $1.8 billion and retirement or repayment of securities totaled $2.2 billion.
Special purpose subsidiaries of the Company have issued mandatorily redeemable preferred securities. See Note 9 to the financial statements under "Preferred Securities" for additional information.
Composite financing rates for long-term debt, preferred stock and preferred securities for the years 1997 through 1999, as of year-end, were as follows:
1999 1998 1997 ---------------------------------- Composite interest rate on long-term debt 5.48% 5.64% 6.11% Composite preferred stock dividend rate 4.60 5.52 5.18 Composite preferred securities dividend rate 7.49 7.89 7.89 - ------------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations decreased by $206 million in 1999, primarily due to lower retail revenues.
The Company estimates that construction expenditures for the years 2000 through 2002 will total $1.2 billion, $1.5 billion and $1.5 billion, respectively. Investments in additional combustion turbine and combined cycle generating units, transmission and distribution facilities, enhancements to existing generating plants, and equipment to comply with environmental requirements are planned.
Cash requirements for improvement fund requirements, redemptions announced, and maturities of long-term debt are expected to total $168 million during 2000 through 2002.
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 $30 million each year in 2000, 2001 and 2002. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning."
Sources of Capital
The Company expects to meet future capital requirements primarily using funds generated from operations and equity funds from Southern 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 2000. 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 also consisted of unsecured debt and trust preferred securities. In this regard, the Company
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1999 Annual Report
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.
ENVIRONMENTAL ISSUES
Clean Air Act
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 are 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 currently uses emission allowances and increased fuel switching. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment requirements increased total construction expenditures by $38 million.
The State of Georgia submitted a plan for nitrogen oxide emission reductions in Atlanta's ozone non-attainment area on October 29, 1999. The Environmental Protection Agency (EPA) found this plan to be deficient and required the State to address the shortfalls of the plan. Based on the revised plan approved by the Georgia Department of Natural Resources on January 26, 2000, the Company estimates its capital expenditures to comply with the plan to be approximately $713 million through 2003, of which $705 million remains to be spent. It is still uncertain at this time what additional controls may be required at the Company's plants beyond the recently submitted plan.
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.
Environmental Protection Agency Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Bowen and Scherer plants. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued a notice of violation to the Company relating to these two plants. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1999 Annual Report
Other Environmental Issues
In July 1997, the 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 rule to the states for implementation. The final rule affects 22 states including Georgia. The EPA's July 1997 standards and the September 1998 rule are being challenged in the courts by several states and industry groups. Implementation of the final state rules for these three initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur costs to clean up properties currently or previously owned. The Company conducts studies to determine the extent of any required clean-up costs and has recognized in the financial statements costs to clean up known sites. These costs for the Company amounted to $4 million, $6 million and $4 million in 1999, 1998 and 1997, respectively. Additional sites may require environmental remediation for which the Company may be liable for a portion of or all required clean-up costs. See Note 3 to the financial statements under "Other Environmental Contingencies" for information regarding the Company's potentially responsible party status at a site in Brunswick, Georgia, and the status of sites listed on the State of Georgia's hazardous site inventory.
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 any new standards will depend on the development and implementation of applicable regulations.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change, electromagnetic fields and other environmental and health concerns could significantly affect the Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
The Company's 1999 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; 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 Georgia Power Company 1999 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the parent company of five integrated Southeast utilities, Southern Company Services (SCS), 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 integrated Southeast utilities (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four states. Contracts among the integrated Southeast utilities - related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC). SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Southern Energy's businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the Southeastern United States.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of 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.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $253 million, $251 million, and $218 million during 1999, 1998, and 1997, respectively.
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services; general operations, management and technical services; administrative services including procurement, accounting and statistical, employee relations, and systems and procedures services; strategic planning and budgeting services; and other services with respect to business and operations. Costs for these services amounted to $270 million, $269 million, and $220 million during 1999, 1998, and 1997, respectively.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Pursuant to the terms of the GPSC's 1998 rate order, the Company recorded $85 million in 1999 of additional amortization of premium on reacquired debt. See Note 3 under "Retail Rate Orders" for additional information. Regulatory assets and (liabilities) reflected in the Company's Balance Sheets at December 31 relate to the following:
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NOTES (continued) Georgia Power Company 1999 Annual Report
1999 1998 ----------------------- (in millions) Deferred income taxes $ 591 $ 604 Deferred income tax credits (267) (284) Premium on reacquired debt 99 174 Corporate building lease 54 53 Vacation pay 47 44 Postretirement benefits 33 36 Department of Energy assessments 24 26 Deferred nuclear outage costs 26 24 Other, net 3 12 - --------------------------------------------------------------- Total $ 610 $ 689 ===============================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Georgia, and to wholesale customers in the Southeast.
The Company 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. 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 1999, $74 million in 1998, and $76 million in 1997. 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 and potentially additional spent fuel pool rack capacity at Plant Hatch during 2000 are in progress. In addition, through Southern Nuclear, Georgia Power is a member of Private Fuel Storage, LLC, a joint utility effort to develop a private spent fuel storage facility for temporary storage of spent nuclear fuel. This facility is planned to begin operation as early as the year 2003.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is to be funded in part by a special assessment on utilities with nuclear plants. 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, 1999, to be approximately $21.4 million. This obligation is recorded in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3 percent in 1999, 3.2 percent in 1998, and 3.1 percent in 1997. In addition, the Company recorded accelerated depreciation of electric plant of $314 million in 1998 and $159 million in 1997. The Company did not record any accelerated depreciation in 1999. These charges are recorded in the accumulated provision for depreciation. See Note 3 under "Retail Rate Orders" 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.
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NOTES (continued) Georgia Power Company 1999 Annual Report
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.
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 percent 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 1999 and fund balance as of December 31, 1999 were:
Plant Plant Hatch Vogtle - --------------------------------------------------------------- (in millions) Amount expensed in 1999 $ 17 $ 9 =============================================================== (in millions)
Accumulated provisions: External trust funds, at fair value $222 $149 Internal reserves 22 12 - --------------------------------------------------------------- Total $244 $161 ===============================================================
Effective January 1, 1999, the GPSC increased the annual provision for decommissioning expenses to $26 million from $20 million in 1998 and 1997. 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 percent and an estimated trust earnings rate of 6.5 percent. The Company expects the GPSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
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NOTES (continued) Georgia Power Company 1999 Annual Report
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. For the years 1999, 1998 and 1997, the average AFUDC rates were 5.61 percent, 6.71 percent and 7.60 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 2.0 percent for 1999, 1998, and 1997.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost, less regulatory disallowances and impairments. Original cost includes: materials; labor; payroll-related costs such as taxes, pensions, and other benefits; and the cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is capitalized.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Financial Instruments
The Company'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, 1999 $2,758 $2,604 At December 31, 1998 3,058 3,105 Preferred securities: At December 31, 1999 789 680 At December 31, 1998 689 716 - --------------------------------------------------------------
The fair values for securities were based on either closing market prices or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed pension plans that cover substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all these employees may become eligible for such benefits when they retire. The Company funds postretirement trusts to the extent required by the GPSC and FERC. The measurement date for plan assets and obligations is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were:
1999 1998 - ----------------------------------------------------------------- Discount 7.50% 6.75% Annual salary increase 5.00 4.25 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 --------------------------- 1999 1998 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $1,217 $1,119 Service cost 33 30 Interest cost 80 82 Benefits paid (57) (55) Actuarial (gain) loss and employee transfers (68) 41 - ---------------------------------------------------------------- Balance at end of year $1,205 $1,217 ================================================================
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NOTES (continued) Georgia Power Company 1999 Annual Report
Plan Assets --------------------------- 1999 1998 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $1,859 $1,931 Actual return on plan assets 313 11 Benefits paid (57) (55) Employee transfers (8) (28) - ---------------------------------------------------------------- Balance at end of year $2,107 $1,859 ================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in millions) Funded status $ 902 $ 642 Unrecognized transition obligation (30) (35) Unrecognized prior service cost 41 45 Unrecognized net actuarial gain (767) (548) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 146 $ 104 ===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997 - --------------------------------------------------------------- (in millions) Service cost $ 33 $ 30 $ 30 Interest cost 80 82 82 Expected return on plan assets (137) (127) (121) Recognized net actuarial gain (17) (20) (18) Net amortization (1) (1) (1) - --------------------------------------------------------------- Net pension income $ (42) $ (36) $ (28) ===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------------- 1999 1998 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $464 $435 Service cost 8 7 Interest cost 30 32 Benefits paid (19) (16) Actuarial loss and employee transfers (45) 6
- ---------------------------------------------------------------- Balance at end of year $438 $464 =================================================================
Plan Assets --------------------------- 1999 1998 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $150 $122 Actual return on plan assets 11 4 Employer contributions 35 40 Benefits paid (19) (16) - ---------------------------------------------------------------- Balance at end of year $177 $150 ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows: 1999 1998 - --------------------------------------------------------------- (in millions) Funded status $(261) $(314) Unrecognized transition obligation 122 131 Unrecognized net actuarial loss 10 57 Fourth quarter contributions 14 19 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(115) $(107) ===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997 - --------------------------------------------------------------- (in millions) Service cost $ 8 $ 7 $ 7 Interest cost 30 32 32 Expected return on plan assets (10) (9) (7) Recognized net actuarial loss 1 1 1 Net amortization 9 9 9 - --------------------------------------------------------------- Net postretirement cost $ 38 $40 $42 ===============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 7.74 percent for 1999, decreasing gradually to 5.50 percent through the year 2005, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 1999 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $ 36 $ (30) Service and interest costs 3 (3) ===============================================================
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NOTES (continued) Georgia Power Company 1999 Annual Report
3. CONTINGENCIES & REGULATORY MATTERS
Retail Rate Orders
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 were decreased by $262 million on an annual basis effective January 1, 1999, and by an additional $24 million effective January 1, 2000. The order further provides for $85 million in each year, plus up to $50 million of any earnings above the 12.5 percent return during the second and third years, to be applied to accelerated amortization or depreciation of assets. Two-thirds of any additional earnings above the 12.5 percent return will be applied to rate reductions, with the remaining one-third retained by the Company. Pursuant to the order, in 1999 the Company recorded $85 million in accelerated amortization of premium on reacquired debt. The Company also recorded $79 million of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity. Refunds will be made to customers in 2000. This refund is presented in the financial statements under other current liabilities on the Balance Sheet. The Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent, and is 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 above 12.5 percent were used to accelerate the amortization of regulatory assets or depreciation of electric plant. Additionally, the Company was required to record $14 million annually of accelerated depreciation of electric plant. During 1998 and 1997, for earnings above the 12.5 percent retail return, the Company recorded charges of $292 million and $135 million, respectively. These charges are presented in the financial statements as depreciation expense of electric plant and as an addition to the accumulated provision for depreciation.
Environmental Protection Agency (EPA) Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Bowen and Scherer plants. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units beginning at the point of the alleged violations. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day.
The EPA concurrently issued a notice of violation to the Company relating to these two plants. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place
An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates.
Other Environmental Contingencies
The State of Georgia submitted a plan for nitrogen oxide emission reductions in Atlanta's ozone non-attainment area on October 29, 1999. The EPA found this plan to be deficient and required the State to address the shortfalls of the plan. Based on the revised plan approved by the Georgia Department of Natural Resources on January 26, 2000, the Company estimates its capital costs to comply with the plan to be approximately $713 million through 2003, of which $705 million remains to be spent. It is still uncertain at this time what additional controls may be required at the Company's plants beyond the recently submitted plan.
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
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NOTES (continued) Georgia Power Company 1999 Annual Report
with respect to a site in Brunswick, Georgia. As of December 31, 1999, 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 31 sites which may require environmental remediation that were either previously or are currently owned by the Company. The majority of these sites are electrical power substations and power generation facilities. The Company has remediated ten electrical substations on the list at a cumulative cost of approximately $3 million through December 31, 1999. The State has removed from the list two power generation facilities following the assessment which indicated no remediation was necessary. In addition, the Company has recognized approximately $26 million in cumulative expenses through December 31, 1999 for the assessment of the remaining sites on the list and the anticipated clean-up cost for 12 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 determines whether remediation is required. If all listed sites were required to be remediated, the Company could incur expenses of up to approximately $6 million in additional clean-up costs and construction expenditures of up to approximately $37 million to develop new waste management facilities or install additional pollution control devices.
The accrued costs for environmental remediation obligations are not discounted to their present value.
Rocky Mountain Status
In June 1996, the GPSC initiated a review of the Rocky Mountain 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. Under the rate order approved by the GPSC on December 18, 1998, the Company accepted the rate base allowance and, in December 1998, 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.
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.
Nuclear Performance Standards
The GPSC has adopted a nuclear performance standard for the Company's nuclear generating units under which the performance of plants Hatch and Vogtle is evaluated every three years. The performance standard is based on each unit's capacity factor as compared to the average of all comparable U.S. nuclear units operating at a capacity factor of 50 percent or higher during the three-year period of evaluation. Depending on the performance of the units, the Company could receive a monetary award or penalty under the performance standards criteria.
In January 1997, the GPSC approved a performance award of approximately $11.7 million for performance during the 1993-1995 period. This award was collected through the retail fuel cost recovery provision and recognized in income over the 36-month period ending in December 1999. In February 2000, the GPSC approved a performance award of approximately $7.8 million for performance during the 1996-1998 period. This award is being collected through the retail fuel cost recovery provision and recognized in income over a 36-month period that began in January 2000.
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NOTES (continued) Georgia Power Company 1999 Annual Report
4. COMMITMENTS
Construction Program
The Company is constructing a ten unit, 800 megawatt combustion turbine peaking power plant. Units one through eight will begin operation in 2000; units nine and ten will begin operation in 2001. The Company also plans to construct a 570 megawatt combined cycle unit that will begin operation in 2002, and an addition of two 568 megawatt combined cycle units at Plant Wansley, to begin operation in 2002. 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 $1.2 billion in 2000, $1.5 billion in 2001, and $1.5 billion in 2002.
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, 1999 were as follows:
Minimum Year Obligations - ---- ------------ (in millions) 2000 $ 659 2001 475 2002 381 2003 328 2004 300 2005 and beyond 787 - ---------------------------------------------------------------- Total minimum obligations $2,930 ================================================================
Additional commitments for coal and for nuclear fuel will be required in the future to supply the Company's fuel needs.
Purchased Power Commitments
The Company and an affiliate, Alabama Power Company, own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of the units has been sold equally to the Company and Alabama Power Company under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, debt service and return on investment, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party's right to cancel upon two year's notice. The Company's share of expenses included in purchased power from affiliates in the Statements of Income, is as follows:
1999 1998 1997 --------------------------------- (in millions) Energy $51 $45 $45 Capacity 29 30 30 - -------------------------------------------------------------- Total $80 $75 $75 ============================================================== Kilowatt-hours 3,338 3,146 3,038 - --------------------------------------------------------------
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 $57 million, $56 million, and $54 million in 1999, 1998, and 1997, respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments - ---- ---------------------- (in millions) 2000 $ 60 2001 59 2002 58 2003 58 2004 55 2005 and beyond 594 - ---------------------------------------------------------------- Total capacity payments $ 884 ================================================================
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NOTES (continued) Georgia Power Company 1999 Annual Report
Portions of the payments noted above relate to costs in excess of Plant Vogtle's allowed investment for ratemaking purposes. The present value of these portions was written off in 1987 and 1990.
The Company has entered into other various long-term commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 1999 were as follows:
Year Other Obligations - --- ---------------------- (in millions) 2000 $ 21 2001 22 2002 39 2003 41 2004 40 2005 and beyond 412 - ---------------------------------------------------------------- Total other obligations $ 575 ================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $11 million for 1999, $13 million for 1998, and $11 million for 1997. At December 31, 1999, estimated minimum rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations - ---- -------------------------- (in millions) 2000 $ 12 2001 13 2002 13 2003 13 2004 13 2005 and beyond 115 - ----------------------------------------------------------------- Total minimum obligations $ 179 =================================================================
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plants. The act provides funds up to $9.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $88 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment for the Company, excluding any applicable state premium taxes, -- based on its ownership and buyback interests -- is $178 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can be insured against increased costs of replacement power in an amount up to $3.5 million per week -- starting 12 weeks after the outage -- for one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the three NEIL policies would be $21 million.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies should be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property or replacement power, may be subject to applicable state premium taxes.
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NOTES (continued) Georgia Power Company 1999 Annual Report
6. JOINT OWNERSHIP AGREEMENTS
Except as otherwise noted, the Company has contracted to operate and maintain all jointly owned generating facilities. The Company includes its proportionate share of plant operating expenses in the corresponding operating expenses in the Statements of Income.
The Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company also jointly owns Plant McIntosh with Savannah Electric and Power Company who operates the plant. The Company and Florida Power Corporation (FPC) jointly own a combustion turbine unit operated by FPC.
At December 31, 1999, 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% $3,297* $1,630 Plant Hatch (nuclear) 50.1 857 604 Plant Wansley (coal) 53.5 299 145 Plant Scherer (coal) Units 1 and 2 8.4 112 51 Unit 3 75.0 544 193 Plant McIntosh Common Facilities 75.0 19 1 (combustion-turbine) Rocky Mountain 25.4 169* 66 (pumped storage) Intercession City 33.3 11 ** (combustion-turbine) - -------------------------------------------------------------------- * Investment net of write-offs. ** Less than $1 million.
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other integrated Southeast utilities of Southern Company have long-term contractual agreements for the sale of capacity and energy to non-affiliated utilities located outside the system's service area. These 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) 1999 $ 32 162 1998 32 162 1997 42 159 -------------------------------------
Unit power from specific generating plants is being sold to Florida Power & Light Company (FP&L), FPC, Jacksonville Electric Authority (JEA), and the City of Tallahassee, Florida. Under these agreements, the Company sold approximately 162 megawatts of capacity in 1999 and is scheduled to sell approximately 124 megawatts of capacity in 2000. After 2000, capacity sales will decline to approximately 101 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1999, tax-related regulatory assets were $591 million and tax-related regulatory liabilities were $267 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:
1999 1998 1997 ------------------------------- Total provision for income taxes: (in millions) Federal: Currently payable $ 333 $415 $352 Deferred - Current year 114 131 49 Reversal of prior years (148) (218) (68) Deferred investment tax credits - 7 - - ----------------------------------------------------------------- 299 335 333 - ----------------------------------------------------------------- State: Currently payable 54 77 65 Deferred - Current year 5 18 8 Reversal of prior years (11) (31) (11) Deferred investment tax credits 5 - - - ----------------------------------------------------------------- 53 64 62 - ----------------------------------------------------------------- Total 352 399 395 =================================================================
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NOTES (continued) Georgia Power Company 1999 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:
1999 1998 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,766 $1,670 Property basis differences 729 854 Other 155 158 - ----------------------------------------------------------------- Total 2,650 2,682 - ----------------------------------------------------------------- Deferred tax assets: Other property basis differences 200 211 Federal effect of state deferred taxes 93 95 Other deferred costs 109 96 Disallowed Plant Vogtle buybacks 22 23 Other 26 21 - ----------------------------------------------------------------- Total 450 446 - ----------------------------------------------------------------- Net deferred tax liabilities 2,200 2,236 Portion included in current assets 3 13 - ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $2,203 $2,249 =================================================================
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 $20 million in 1999, $22 million in 1998, and $15 million in 1997. At December 31, 1999, 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:
1999 1998 1997 -------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 2 6 4 Other (2) (4) (4) - --------------------------------------------------------------- Effective income tax rate 39% 41% 39% ===============================================================
Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis.
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, 1999, $881 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
Statutory business trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities as follows:
Date of Maturity Issue Amount Rate Notes Date --------------------------------------------------- (millions) (millions) Trust I 8/1996 $225.00 7.75% $232 6/2036 Trust II 1/1997 175.00 7.60 180 12/2036 Trust III 6/1997 189.25 7.75 195 3/2037 Trust IV 2/1999 200.00 6.85 206 3/2029
Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above.
The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with respect to the preferred securities.
The Trusts are subsidiaries of the Company, and accordingly are consolidated in the Company's financial statements.
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NOTES (continued) Georgia Power Company 1999 Annual Report
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 $457.5 million of its first mortgage bonds outstanding at December 31, 1999, 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
The Company incurred debt in connection with the issuance of 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 2000, the Company had unused credit arrangements with banks totaling $1.3 billion, of which $752 million expires at various times during 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 20, 2000, 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.
Approximately $162 million of the $752 million arrangements expiring during 2000 allow for two-year term loans executable upon expiration date of the 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.
These unused credit arrangements provide liquidity support to the Company's variable rate pollution control bonds. The amount of variable rate pollution control bonds outstanding requiring that liquidity support as of December 31, 1999, was $250 million.
In addition, the Company borrows under uncommitted lines of credit with banks and through a $500 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 1999.
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, 1999 and 1998, 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, 1999 and 1998, the interest and lease amortization deferred on the Balance Sheets are $54 million and $53 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.
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NOTES (continued) Georgia Power Company 1999 Annual Report
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:
1999 1998 ------------------ (in millions)
Bond improvement fund requirements $ 5 $ 9 Capital lease - current portion 1 - First mortgage bond maturities and redemptions 100 390 Pollution control bond maturities and redemptions 50 - - ---------------------------------------------------------------
Total long-term debt 156 399 Preferred stock - 36 - ---------------------------------------------------------------
Total $156 $435 ===============================================================
The Company's first mortgage bond indenture includes an improvement fund requirement that amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to January 1 of each year, other than those issued to collateralize pollution control obligations. The requirement may be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 2/3 times the requirement.
Redemption of Securities
The Company plans to continue, to the extent possible, a program of redeeming or replacing debt and preferred 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. 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 1999 and 1998 is as follows:
Net Income After Dividends on Operating Operating Preferred Quarter Ended Revenues Income Stock - --------------------------------------------------------------------- (in millions) -------------------------------------------- March 1999 $ 931 $224 $ 92 June 1999 1,092 299 138 September 1999 1,466 557 296 December 1999 968 200 15
March 1998 $ 984 $257 $ 106 June 1998 1,226 286 137 September 1998 1,530 514 255 December 1998 998 143 72 - ---------------------------------------------------------------------
Under the 1998 rate order, the Company recorded $85 million of accelerated amortization which was recorded monthly throughout 1999 as an operating expense. See Note 3 to the financial statements under "Retail Rate Orders" for additional information. In December 1999, in accordance with the order, the Company reclassified this $85 million to amortization of premium on reacquired debt. The 1999 fourth quarter operating income reflects this reclassification.
The quarterly operating income data above has been reclassified to reflect the Company's current presentation of income tax expense.
The Company's business is influenced by seasonal weather conditions.
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GULF POWER COMPANY
FIANANCIAL SECTION
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MANAGEMENT'S REPORT Gulf Power Company 1999 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 Travis J. Bowden President and Chief Executive Officer
/s/Arlan E. Scarbrough Arlan E. Scarbrough Chief Financial Officer
February 16, 2000
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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, 1999 and 1998, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-124 through II-139) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Atlanta, Georgia February 16, 2000
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1999 net income after dividends on preferred stock was $53.7 million, a decrease of $2.8 million from the previous year. In 1998, earnings were $56.5 million, down $1.1 million when compared to 1997. The decrease in earnings in 1999, as well as 1998, was primarily a result of higher expenses than in the prior year.
Revenues
Operating revenues increased in 1999 and 1998 when compared to 1998 and 1997, respectively. The following table summarizes the factors impacting operating revenues for the past three years:
Increase (Decrease) From Prior Year --------------------------------------- 1999 1998 1997 --------------------------------------- (in thousands) Retail -- Growth and price change $10,348 $15,021 $ 4,005 Weather (7,879) 6,656 (5,277) Regulatory cost recovery and other 1,173 (34,179) (7,837) - -------------------------------------------------------------------- Total retail 3,642 (12,502) (9,109) - -------------------------------------------------------------------- Sales for resale-- Non-affiliates 461 (1,804) 496 Affiliates 23,468 25,882 (1,002) - -------------------------------------------------------------------- Total sales for resale 23,929 24,078 (506) Other operating revenues (3,990) 13,086 1,106 - -------------------------------------------------------------------- Total operating revenues $23,581 $24,662 $(8,509) ==================================================================== Percent change 3.6% 3.9% (1.3)% - --------------------------------------------------------------------
Retail revenues of $512.8 million in 1999 increased $3.6 million, or 0.7 percent, from the prior year due primarily to an increase in the number of retail customers served by the Company. Retail revenues for 1998 decreased $12.5 million, or 2.4 percent, when compared to 1997 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 Committments" for further information.
The 1999 increase in regulatory cost recovery and other retail revenues over 1998 is primarily attributable to the recovery of increased purchased power capacity costs. The 1998 decrease in regulatory cost recovery and other retail revenues over 1997 is primarily attributable to 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 $128.5 million in 1999, an increase of $24 million, or 23 percent, over 1998 primarily 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:
1999 1998 1997 ---------------------------------------- (in thousands) Capacity $19,792 $22,503 $24,899 Energy 20,251 14,556 18,160 - ------------------------------------------------------------- Total $40,043 $37,059 $43,059 =============================================================
Declining capacity revenues are due primarily to the decline in net plant investment related to these sales. In addition, the decline in 1999 reflects a reduction in the authorized rate of return on the equity component of the investment.
Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales have little impact on earnings.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1999 Annual Report
Other operating revenues decreased in 1999 and 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.
Energy Sales
Kilowatt-hour sales for 1999 and the percent changes by year were as follows:
KWH Percent Change ------------- ------------------------------- 1999 1999 1998 1997 ------------- ------------------------------- (millions)
Residential 4,471 0.8% 7.7% (1.0)% Commercial 3,223 3.6 7.4 3.2 Industrial 1,846 0.7 (3.7) 5.3 Other 19 0.0 4.7 1.6 ------------- Total retail 9,559 1.7 5.2 1.6 Sales for resale Non-affiliates 1,562 16.4 (12.4) (0.2) Affiliates 2,512 42.9 107.3 19.5 ------------- Total 13,633 9.0 10.5 2.5 ==================================================================
In 1999, total retail energy sales increased due to increases from 1998 in the number of residential, commercial and industrial customers. Total energy sales increased in 1998 when compared to 1997 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. See "Future Earnings Potential" for information on the Company's initiatives to remain competitive and to meet conservation goals set by the Florida Public Service Commission (FPSC).
An increase in energy sales for resale to non-affiliates of 16.4 percent in 1999 when compared 1998 and a decrease of 12.4 percent in 1998 when compared to 1997 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 1999 increased $26.8 million, or 5.1 percent, over the amount recorded in 1998 due primarily to higher fuel and purchased power expenses, offset by lower other operation expenses. In 1998, total operating expenses increased $26.5 million, or 5.3 percent, from 1997. The increase was due primarily to higher fuel, purchased power, and maintenance expenses offset by lower other operation expenses.
Fuel expenses in 1999, when compared to 1998, increased $11.5 million, or 5.9 percent. In 1998, fuel expenses increased $16.6 million, or 9.2 percent, when compared to 1997. The increases were the result of increased generation resulting from a higher demand for energy, while average fuel costs decreased as noted below.
Purchased power expenses increased in 1999 by $13.2 million, or 30.2 percent, over 1998 and purchased power expenses for 1998 increased over 1997 by $6.9 million, or 18.8 percent, due to a higher demand for energy in both years.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1999 1998 1997 ------------------------------- Total generation (millions of kilowatt-hours) 13,095 11,986 10,435 Sources of generation (percent) Coal 97.4 98.0 99.6 Oil and gas 2.6 2.0 0.4 Average cost of fuel per net kilowatt-hour generated (cents)-- 1.60 1.69 1.99 - ---------------------------------------------------------------------
Other operation expenses decreased $4.3 million, or 3.6 percent, in 1999 from the 1998 level and $7.3 million, or 5.7 percent, in 1998 from the 1997 level due to a decrease in the amortization costs of prior year payments related to renegotiations of coal supply contracts. The 1998 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1999 Annual Report
Depreciation and amortization expense increased $5.5 million, or 9.2 percent, in 1999 when compared to 1998 due primarily to a reduction in the amortization of gains from the 1998 sale of emission allowances.
Maintenance expenses in 1998 increased by $9.3 million, or 19.4 percent, over 1997 due primarily to scheduled maintenance at Plant Crist and Plant Smith and increased transmission and distribution maintenance.
Interest on long-term debt in 1999 increased $1.7 million, or 8.4 percent, when compared to 1998 due primarily to two first mortgage bonds maturing in 1998 and being replaced by senior notes at a slightly higher interest rate, and the issuance of $50 million of senior notes in August 1999. In 1998, interest on long-term debt decreased $2.0 million, or 9.1 percent, from 1997 mostly due 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 the replacement in 1998 of the two maturing first mortgage bonds with senior notes at a slightly higher interest rate.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its cost of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
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 early 1999, the FPSC Staff and the Company became involved in serious discussions primarily related to reducing the Company's authorized rate of return. On October 1, 1999 the Office of Public Counsel, the Coalition for Equitable Rates, the Florida Industrial Power Users Group, and the Company jointly filed a petition to resolve the issues. The stipulation included a reduction to retail base rates of $10 million annually and provides for revenues to be shared within set ranges for 1999 through 2002. Customers would receive two-thirds of any revenue within the ranges and the Company would retain one-third. For calendar year 2000, the Company's retail base rate revenues in excess of $352 million up to $368 million will be shared between the Company and its retail customers on the one-third/two-thirds basis. Retail base rate revenues above $368 million for calendar year 2000 will be refunded to the Company's customers. These set ranges increase gradually until the expiration of the plan. The Sharing Plan will be in place until the earlier of the in-service date of Smith Unit 3 or December 31, 2002. The parties could not agree on the appropriate Return on Equity (ROE). Consequently, the Company filed a request to prospectively reduce its authorized ROE range from 11 to 13 percent to 10.5 to 12.5 percent in order to help ensure that the FPSC would approve the stipulation. Both the stipulation and the ROE request were approved by the Commission on October 5, 1999, with an effective date of November 4, 1999.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1999 Annual Report
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. 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 these initiatives materialize, the structure of the utility industry continues to 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 financial condition and results of operation. The Company is attempting to minimize or reduce its cost exposure.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if the Company does not remain a low-cost producer and provide quality service, the Company's energy sales growth could be limited, and this could significantly erode earnings.
In 1996, the FPSC approved a new optional Commercial/Industrial Service Rider (CISR), which is applicable to the rate schedules for the Company's largest existing and potential customers who are able to show they have viable alternatives to purchasing the Company's energy services. The CISR, approved as a pilot program, provides the flexibility needed to enable the Company to offer its services in a more competitive manner to these customers. The publicity of the CISR ruling, increased competitive pressures, and general awareness of customer choice pilots and proposals across the country have stimulated interest on the part of customers in custom tailored offerings. The Company has participated in one-on-one discussions with many of these customers, and has negotiated and executed two Contract Service Agreements within the CISR pilot program. The pilot program ends in September of 2000 and the company is currently reviewing its options.
Every five years the FPSC establishes numeric demand side management goals. The Company proposed numeric goals for the ten-year period from 2000 to 2009. The proposed goals consisted of the total, cost-effective winter and summer peak demand (kilowatts) and annual energy (kilowatt-hour) savings reasonably achievable from demand side management for the residential and commercial/industrial classes. The Company submitted its 2000 Demand Side Management Plan to the FPSC on December 29, 1999. The plan describes the Company's proposed programs it will employ to reach the numeric goals. The plan relies heavily on innovative pricing and energy efficient construction. The FPSC is expected to issue its final order on the Company's 2000 Demand Side Management Plan in mid-April 2000.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. To facilitate the development of RTOs, the FERC will convene regional conferences for utilities, customers, and other members of the public to discuss the formation of RTOs. In addition to participating in the regional conferences, utilities owning transmission systems, including Southern Company, are required to make a filing by October 15, 2000. The filing must contain either a proposal for RTO participation or a description of the efforts made to participate in an RTO, the reasons for non-participation, any obstacles to participation, and any
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1999 Annual Report
plans for further work toward participation. The RTOs that are proposed in the filings should be operational by December 15, 2001. Southern Company is evaluating this issue and formulating its response. The outcome of this matter cannot now be determined.
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.
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, 1999, 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, 1999, 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 January 1, 2001. 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.
Year 2000 Challenge
The work undertaken by the Company to ensure that all critical computer systems and other date sensitive devices would function correctly in the Year 2000 was successful. There were no material incidents reported and no disruption of electric service within the service area of the Company. There were no reports of significant events regarding third parties that impacted revenues or expenses.
The Company's original projected total costs for Year 2000 readiness were approximately $5 million. Final projected costs were also $5 million with no material costs remaining to be spent in 2000. From its inception through December 31, 1999, the Year 2000 program costs, recognized primarily as expense, amounted to $5 million, of which $2 million was recorded in 1999.
FINANCIAL CONDITION
Overview
The Company's financial condition continues to be very solid. During 1999, gross property additions were $69.8 million. Funds for the property additions were provided by operating activities. See the Statements of Cash Flows for further details.
Financing Activities
In 1999, the Company sold $50 million of senior notes and long-term bank notes totaling $27 million were retired. The remaining proceeds from this issuance were used to reduce short-term borrowing requirements. See the Statements of Cash Flows for further details.
Composite financing rates for the years 1997 through 1999 as of year end were as follows:
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1999 Annual Report
1999 1998 1997 ----------------------------- Composite interest rate on long-term debt 6.0% 6.1% 5.9% Composite rate on trust preferred securities 7.3% 7.3% 7.6% Composite preferred stock dividend rate 5.1% 5.1% 6.1% - -----------------------------------------------------------------
The composite interest rate on long-term debt decreased in 1999 primarily due to lower interest rates on variable rate pollution control bonds.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $428 million for the three years beginning in 2000 ($106 million in 2000, $232 million in 2001, and $90 million in 2002). These amounts include $198.8 million for the years 2000 through 2002 for the estimated cost of a 574 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. The remaining property additions budget is primarily for maintaining and upgrading transmission and distribution facilities and generating plants. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Other Capital Requirements
The Company will continue to retire higher-cost debt and preferred securities and replace these securities with lower-cost capital as market conditions and terms of the instruments permit.
Environmental Matters
In November 1990, the Clean Air Act 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.
For Phase II sulfur dioxide compliance, Southern Company currently uses emission allowances and increased fuel switching. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as required to meet Phase II limits and ozone non-attainment requirements. Compliance for Phase II and initial ozone non-attainment requirements increased total estimated construction expenditures by approximately $105 million. 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 reduction rule to the states for implementation. The final rule affects 22 states, including Alabama and Georgia.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1999 Annual Report
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's July 1997 standards and the September 1998 rule are being challenged in the courts by several states and industry groups. Implementation of the final state rules for these three initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules.
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 any new standards will depend on the development and implementation of applicable regulations.
On November 3, 1999, the EPA brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, including the five facilities mentioned previously and the Company's Plants Crist and Scherer. See Note 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. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1999 Annual Report
Sources of Capital
At December 31, 1999, the Company had approximately $15.8 million of cash and cash equivalents and $41.5 million of unused committed lines of credit with banks to meet its short-term cash needs. Refer to the Statements of Cash Flows for details related to the Company's financing activities. See Note 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
The Company's 1999 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; 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 1999 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Gulf Power Company is a wholly owned subsidiary of Southern Company, which is the parent company of five integrated Southeast utilities, 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 integrated Southeast utilities -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four states. Gulf Power Company provides electric service to the northwest panhandle of Florida. Contracts among the integrated Southeast utilities -- related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power --are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Southern Energy businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Florida Public Service Commission (FPSC). The Company follows generally accepted accounting principles and complies with the accounting policies and practices prescribed by the FPSC and the FERC. 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.
Related-Party Transactions
The Company has an agreement with Southern Company Services, Inc. (a wholly owned subsidiary of Southern Company) under which the following services are rendered to the company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $43 million, $40 million, and $36 million during 1999, 1998, and 1997, respectively.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following:
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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 1999 Annual Report
1999 1998 -------------------------- (in thousands) Deferred income tax debits $25,264 $ 25,308 Deferred loss on reacquired debt 17,360 18,883 Environmental remediation 5,745 7,076 Vacation pay 4,199 4,035 Regulatory clauses under (over) recovery, net 8,486 3,700 Accumulated provision for property damage (5,528) (1,605) Deferred income tax credits (49,693) (52,465) Other, net (1,255) (480) - ------------------------------------------------------------------ Total $ 4,578 $ 4,452 ==================================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Regulatory Cost Recovery Clauses
The Company currently operates as a vertically integrated utility providing electricity to retail customers within its service area located in northwest Florida and to wholesale customers in the Southeast.
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 retail 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 retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted monthly for differences between recoverable costs and amounts actually reflected in current rates.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.8 percent in 1999 and 1998 and 3.6 percent in 1997. 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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
Temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
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NOTES (continued) Gulf Power Company 1999 Annual Report
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, 1999 $367,449 $349,791 At December 31, 1998 $344,341 $357,100 Capital trust preferred securities: At December 31, 1999 $85,000 $69,092 At December 31, 1998 $85,000 $89,400 - --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on either closing market prices or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Provision for Injuries and Damages
The Company is subject to claims and suits arising in the ordinary course of business. As permitted by regulatory authorities, the Company provides for the uninsured costs of injuries and damages by charges to income amounting to $1.2 million annually. The expense of settling claims is charged to the provision to the extent available. The accumulated provision of $1.8 million and $1.3 million at December 31, 1999 and 1998, respectively, is included in other current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
The Company provides for the cost of repairing damages from major storms and other uninsured property damages. This includes the full cost of 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, 1999 and 1998, the accumulated provision for property damage was $5.5 million and $1.6 million, respectively. 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. The Company accrued $5.5 million in 1999 and $6.5 million in 1998 to the accumulated provision for property damage. The Company charged $1.6 million to the provision account in 1999. 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 required by the Company's regulatory commissions. The measurement date for plan assets and obligations is September 30 for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $143,012 $130,794 Service cost 4,490 4,107 Interest cost 9,440 9,572 Benefits paid (6,862) (6,663) Actuarial loss (gain) and employee transfers (8,113) 5,202 - --------------------------------------------------------------- Balance at end of year $141,967 $143,012 ===============================================================
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NOTES (continued) Gulf Power Company 1999 Annual Report
Plan Assets --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $212,934 $222,196 Actual return on plan assets 35,971 1,310 Benefits paid (6,862) (6,663) Employee transfers (558) (3,909) - --------------------------------------------------------------- Balance at end of year $241,485 $212,934 ===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in thousands) Funded status $99,518 $ 69,922 Unrecognized transition obligation (4,323) (5,043) Unrecognized prior service cost 4,495 4,869 Unrecognized net gain (81,956) (55,978) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $17,734 $13,770 ===============================================================
Components of the pension plan's net periodic cost were as follows:
1999 1998 1997 - ----------------------------------------------------------------- Service cost $4,490 $ 4,107 $ 3,897 Interest cost 9,440 9,572 9,301 Expected return on plan assets (15,968) (14,827) (13,675) Recognized net gain (1,579) (1,891) (1,656) Net amortization (347) (347) (347) - ----------------------------------------------------------------- Net pension income $(3,964) $(3,386) $ (2,480) =================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $49,303 $39,669 Service cost 1,087 946 Interest cost 3,261 3,123 Benefits paid (1,177) (1,068) Actuarial (loss) gain and employee transfers (4,464) 3,614 Amendments - 3,019 - --------------------------------------------------------------- Balance at end of year $48,010 $49,303 ===============================================================
Plan Assets --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $9,603 $9,455 Actual return on plan assets 1,525 54 Employer contributions 1,245 1,162 Benefits paid (1,177) (1,068) - --------------------------------------------------------------- Balance at end of year $11,196 $9,603 ===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in thousands) Funded status $(36,814) $(39,700) Unrecognized transition obligation 4,723 5,079 Unrecognized prior service cost 2,741 2,900 Unrecognized net loss 2,620 8,187 Fourth quarter contributions 300 - - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(26,430) $(23,534) ===============================================================
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NOTES (continued) Gulf Power Company 1999 Annual Report
Components of the postretirement plan's net periodic cost were as follows:
1999 1998 1997 - --------------------------------------------------------------- Service cost $1,087 $ 946 $ 896 Interest cost 3,261 3,123 2,845 Expected return on plan assets (794) (717) (641) Transition obligation 356 356 356 Prior service cost 159 119 - Recognized net loss 264 128 184 - --------------------------------------------------------------- Net postretirement cost $4,333 $3,955 $3,640 ===============================================================
The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits were:
1999 1998 - -------------------------------------------------------- Discount 7.50% 6.75% Annual salary increase 5.00% 4.25% Long-term return on plan assets 8.50% 8.50% - --------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 7.74 percent for 1999, decreasing gradually to 5.5 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, 1999 as follows (in thousands):
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- Benefit obligation $3,627 $(3,086) Service and interest costs $320 $(269) ===============================================================
Work Force Reduction Programs
The Company recorded costs related to work force reduction programs of $0.2 million in 1999, $2.8 million in 1998, and $1.4 million in 1997. The Company has also incurred its pro rata share for the costs of affiliated companies' programs. The costs related to these programs were $0.6 million for 1999, $0.2 million for 1998, and $1.3 million for 1997. The Company has expensed all costs related to these work force reduction programs.
3. CONTINGENCIES AND REGULATORY MATTERS
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 is 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 1999 and 1998, the Company recorded ECRC revenues of $11.6 million and $8.0 million, respectively.
At December 31, 1999, the Company's liability for the estimated costs of environmental remediation projects for known sites was $5.7 million. These estimated costs are expected to be expended from 2000 through 2006. These projects have been approved by the FPSC for recovery through the ECRC discussed above. Therefore, the Company recorded $1.2 million in current assets and current liabilities and $4.5 million in deferred assets and deferred liabilities representing the future recoverability of these costs.
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act
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NOTES (continued) Gulf Power Company 1999 Annual Report
with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day.
The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, including the five facilities mentioned previously and the Company's Plants Crist and Scherer. See Note 6 under "Joint Ownership Agreements" related to the Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place.
An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $106 million in 2000, $232 million in 2001, and $90 million in 2002. 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, 1999, significant purchase commitments were outstanding in connection with the construction program. The Company has budgeted $198.8 million for the years 2000 through 2002 for the estimated cost of a 574 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. 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 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, 1999, the Company had $41.5 million of lines of credit with banks subject to renewal June 1 of each year, all of which remained unused. In addition, the Company has two unused committed lines of credit totaling $61.9 million that were established for liquidity support of its variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees and/or to maintain compensating balances with the banks. The compensating balances, which represent substantially all of the cash of the Company except for daily working funds and like items, are not legally restricted from withdrawal. In addition, the Company has bid-loan facilities with seven major money center banks that total $130 million, of which $50 million was committed at December 31, 1999.
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NOTES (continued) Gulf Power Company 1999 Annual Report
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.
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, 1999 were as follows:
Year Fuel --------- ---------------- (in millions) 2000 $89 2001 70 2002 86 2003 90 2004 91 2005 - 2026 508 ---------------------------------------------------------- Total commitments $934 ==========================================================
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 1999 and $2.8 million in 1998. The annual amounts for 2000 through 2004 are expected to be $2.1 million, $1.7 million, $1.7 million, $1.7 million, and $1.8 million, respectively, and after 2004 are expected to total $14.4 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 1999 Annual Report
At December 31, 1999, 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 $185,714(1) $231,041 Accumulated Depreciation $66,193 $113,687 Construction Work in Progress $276 $2,621
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 $19.8 million in 1999, $22.5 million in 1998, and $24.9 million in 1997. Declining capacity revenues are due primarily to the decline in net plant investment related to these sales. In addition, the decline in 1999 reflects a reduction in the authorized rate of return on the equity component of the investment.
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 1999. Sales will decrease to 209 megawatts per year in 2000 and remain at that level -- unless reduced by FP&L, FPC, and JEA for the periods after 2000 with a minimum of three years notice -- until the expiration of the contracts in 2010.
Capacity and energy sales to FP&L, the Company's largest single customer, provided revenues of $24.3 million in 1999, $22.3 million in 1998, and $25.4 million in 1997, or 3.6 percent, 3.4 percent, and 4.1 percent of operating revenues, respectively.
8. INCOME TAXES
At December 31, 1999, 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 allowance for funds used during construction. At December 31, 1999, the tax-related regulatory liabilities to be credited to customers were $49.7 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:
1999 1998 1997 ------------------------------------ (in thousands) Total provision for income taxes:
Federal-- Current $33,973 $31,746 $34,522 Deferred --current year 16,776 18,485 19,297 --reversal of prior years (22,883) (22,952) (25,778) - -------------------------------------------------------------------- 27,866 27,279 28,041 - -------------------------------------------------------------------- State-- Current 5,267 5,137 5,975 Deferred --current year 2,474 2,745 2,868 --reversal of prior years (2,976) (2,962) (3,434) - -------------------------------------------------------------------- 4,765 4,920 5,409 - -------------------------------------------------------------------- Total $32,631 $32,199 $33,450 ====================================================================
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:
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NOTES (continued) Gulf Power Company 1999 Annual Report
1999 1998 -------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $168,662 $155,833 Property basis differences 6,000 20,330 Other 18,272 17,645 - --------------------------------------------------------------------- Total 192,934 193,808 - --------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 9,293 9,509 Postretirement benefits 8,456 7,644 Other 12,526 10,702 - --------------------------------------------------------------------- Total 30,275 27,855 - --------------------------------------------------------------------- Net deferred tax liabilities 162,659 165,953 Less current portion, net (117) (165) - --------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $162,776 $166,118 =====================================================================
Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation and amortization in the Statements of Income. Credits amortized in this manner amounted to $1.9 million in 1999, $1.9 million in 1998, and $2.2 million in 1997. At December 31, 1999, 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:
1999 1998 1997 ---------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 1 1 1 Difference in prior years' deferred and current tax rate (2) (2) (1) Other, net - (2) (4) - ---------------------------------------------------------------- Effective income tax rate 38% 36% 35% ================================================================
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.
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:
1999 1998 ---------------------- (in thousands) Bond improvement fund requirement $850 $ 850 Less portion to be satisfied by certifying property additions 850 850 - ----------------------------------------------------------------- Cash requirement - - Maturities of first mortgage bonds - - Current portion of other long-term debt - 27,000 - ----------------------------------------------------------------- Total $ - $27,000 =================================================================
The first mortgage bond improvement fund requirement amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to January 1 of each year, other than those issued to collateralize pollution control revenue bond obligations. The requirement may be satisfied by depositing
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NOTES (continued) Gulf Power Company 1999 Annual Report
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, 1999, 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 1999 and 1998 are as follows:
Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock - -------------------------------------------------------------------- (in thousands) March 1999 $134,506 $15,665 $ 4,799 June 1999 166,815 29,253 13,226 September 1999 218,264 54,429 28,582 December 1999 154,514 19,815 7,060
March 1998 $140,950 $19,387 $ 6,853 June 1998 177,130 33,232 13,364 September 1998 199,377 49,837 26,989 December 1998 133,061 19,898 9,315 - --------------------------------------------------------------------
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 1999 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 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 16, 2000
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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, 1999 and 1998, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-152 through II-168) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP Atlanta, Georgia February 16, 2000
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's 1999 net income after dividends on preferred stock of $54.8 million remained relatively flat when compared to 1998. In 1998, earnings were $55.1 million, up $1.1 million from the prior year. This change is primarily attributable to higher retail and wholesale revenues.
Revenues
The following table summarizes the factors impacting operating revenues for the past three years:
Increase (Decrease) From Prior Year ---------------------------------- 1999 1998 1997 ---------------------------------- (in thousands) Retail -- Change in base rates (PEP and ECO Plan) $ 792 $ 335 $ 3,177 Sales growth 7,876 4,787 109 Weather (1,404) 7,091 (1,118) Fuel cost recovery and other 19,603 13,112 948 -------------------------------------------------------------- Total retail 26,867 25,325 3,116 -------------------------------------------------------------- Sales for resale -- Non-affiliates 9,778 16,084 5,464 Affiliates 1,161 8,142 (11,606) -------------------------------------------------------------- Total sales for resale 10,939 24,226 (6,142) Other operating revenues 67 1,992 2,585 -------------------------------------------------------------- Total operating revenues $37,873 $51,543 $ (441) ============================================================== Percent change 6.4% 9.5% (0.1)% --------------------------------------------------------------
Retail revenues of $469 million in 1999 increased 6.1 percent from 1998. This increase resulted primarily from continued growth in the service area and a true-up of the unbilled revenue estimate. Retail revenues for 1998 reflected a 6.1 percent increase over the prior year due to the continued growth in the service area and the positive impact of weather on energy sales.
Fuel revenues generally represent the direct recovery of fuel expense including purchased power. Therefore, changes in recoverable fuel expenses are offset with corresponding changes in fuel revenues and have no effect on net income.
Energy sales to non-affiliates include economy sales and amounts sold under short-term contracts. Sales for resale to non-affiliates are influenced by those utilities' own customer demand, plant availability, and the cost of their predominant fuels.
Included in sales for resale to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. Energy sales to these customers increased 10.2 percent in 1999 and 9.8 percent in 1998, with the related revenues rising 12.1 percent and 11.3 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 1999 and 1998 primarily due to power marketing activities. These increases were offset by increases in purchased power from non-affiliates and, as a result, had no significant effect on net income.
Sales to affiliated companies within the Southern electric system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales have no material impact on earnings.
Below is a breakdown of kilowatt-hour sales for 1999 and the percent change for the last three years:
1999 Percent Change ----------- ------------------------------ KWH 1999 1998 1997 (in millions)
Residential 2,248 - 10.3% (2.0)% Commercial 2,848 8.5 9.0 4.0 Industrial 4,407 18.2 (6.4) 0.6 Other 40 0.8 - 2.6 Total retail 9,543 10.4 2.0 0.9 Sales for Resale -- Non-affiliates 3,256 3.1 9.1 6.2 Affiliates 540 (2.2) 15.2 (31.0) ---------- Total 13,339 8.0 4.3 0.2 ==================================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1999 Annual Report
Total retail sales increased 10.4 percent from 1998 primarily because of continued growth in the service area, industrial customers' recovery from last year's hurricane and a true-up of the unbilled revenue estimate. The unbilled revenue true-up amounted to approximately 3.5 percent of the total increase.
Residential sales decreased slightly in 1999 due to the mild weather in the spring and winter periods, while commercial and industrial sales increased by 8.5 percent and 18.2 percent, respectively. Increased tourism and strong growth impacted commercial sales, while industrial sales were impacted by increased production by several larger industrial customers. Residential and commercial sales increased in 1998 by 10.3 percent and 9.0 percent, respectively, due to sales growth and higher than normal temperatures in the summer months. Sales to industrial customers decreased by 6.4 percent primarily due to a large industrial customer being shut down because of damages incurred from Hurricane Georges.
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 $513 million in 1999 reflecting an increase of $33 million or 6.9 percent over the prior year. The increase was due primarily to higher fuel costs. In 1998, total operating expenses increased by 10.6 percent over the prior year due primarily to higher fuel expenses, higher maintenance and higher other operation costs.
Fuel costs are the single largest expense for the Company. Fuel expenses in 1999 increased 10.3 percent due to an increase in generation resulting from a higher demand for energy. In 1999, expenses related to purchased power from non-affiliates increased 18.3 percent, while expenses related to purchased power from affiliates decreased 14.0 percent which, in total, resulted in a slight increase when compared to 1998. 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.
In 1998, fuel costs increased because of a 3.1 percent increase in generation and a higher average cost of fuel. The increased generation was due to higher demand for energy across the Southern electric system. Expenses related to purchased power from non-affiliates increased, and expenses related to purchased power from affiliates decreased. Further, the higher demand for energy resulted in higher purchased power costs from non-affiliates.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1999 1998 1997 ------------------------- Total generation (millions of kilowatt hours) 11,599 10,610 10,289 Sources of generation (percent) -- Coal 81 80 85 Gas 19 20 15 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.65 1.62 1.54 - --------------------------------------------------------------
Other operation expenses increased 13.9 percent in 1999 primarily due to the amortization of costs associated with the workforce reduction plan and higher distribution expenses. In 1998, other operation expense increased 7.5 percent due to continuing expenses related to a new customer service system, modification of certain information systems for year 2000 readiness, and costs related to workforce reduction programs. Maintenance expenses decreased 6.6 percent in 1999 due to reduced scheduled maintenance. In 1999, depreciation and amortization expenses increased 3.7 percent primarily due to growth in plant investment. Comparisons of taxes other than income taxes for 1999 and 1998 show increases of 4.2 percent and 4.4 percent, respectively, due to higher municipal franchise taxes resulting from higher retail revenues. Interest expense increased due to additional interest related to notes payable and interest accrued on tax audit issues.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1999 Annual Report
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 utility plant with long economic lives. Conventional accounting for historical costs does not recognize this economic loss or the partially offsetting gain that arises through financing facilities with 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 weather to energy sales growth to a less regulated and 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 is also maximizing the utility of invested capital and minimizing the need for additional capital by refinancing, managing the size of its fuel stockpile, raising generating plant availability and efficiency, and aggressively controlling the construction budget.
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 Mississippi Public Service Commission (MPSC) under cost-based regulatory principles. The Federal Energy Regulatory Commission (FERC) regulates the Company's wholesale rate schedules, power sales contracts and transmission facilities.
Operating revenues will be affected by any changes in rates under the Performance Evaluation Plan (PEP), the Company's performance based ratemaking plan, and the ECO Plan. PEP has proven to be a stabilizing force on electric rates, with only moderate changes in rates taking place. The ECO Plan provides for recovery of costs (including costs of capital) associated with environmental projects approved by the MPSC, most of which are required to comply with Clean Air Act Amendments of 1990 (Clean Air Act) regulations. The ECO Plan is operated independently of PEP. Compliance costs related to the Clean Air Act could affect earnings if such costs cannot be recovered. The Company's 1999 ECO Plan was approved, as filed, in 1999 and resulted in a slight decrease in customer prices. The Company filed its 2000 ECO Plan in January, 2000 and, if approved as filed, will result in a slight decrease in customer prices. Refer to Note 3 to the financial statements under "Litigation and Regulatory Matters" for additional information. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters".
Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in Mississippi Power's service area. Currently, the Company is negotiating with certain of its wholesale customers a change in rates and has committed to them that any agreement reached would be effective January 1, 2000. At this time, no agreement has been reached and the ultimate amount of any rate change cannot now be determined.
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, wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers, are driving down electricity sales for resale rates. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1999 Annual Report
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. While 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. 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 Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operation is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
On December 20, 1999, the FERC issued its final ruling on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. To facilitate the development of RTOs, the FERC will convene regional conferences for utilities, customers, and other members of the public to discuss the formation of RTOs. In addition to participating in the regional conferences, utilities owning transmission systems, including the Company, are required to make a filing by October 15, 2000. The filing must contain either a proposal for RTO participation or a description of the efforts made to participate in an RTO, the reasons for non-participation, any obstacles to participation, and any plans for further work toward participation. The RTOs that are proposed in the filings should be operational by December 15, 2001. The Company is evaluating the issue and formulating its response. The outcome of this matter cannot now be determined.
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, 1999, 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, 1999, a near-term 100 basis point change in interest rates would not materially affect the financial statements.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted by January 1, 2001. 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.
Year 2000
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and other date sensitive devices to function correctly in the Year 2000 was successful. There were no material incidents reported and no disruption of electric service within the service area of the Company. There were no reports of significant events regarding third parties that impacted revenues or expenses.
For the Company, original projected total costs for Year 2000 readiness were approximately $5 million. These costs include labor necessary to identify, test, and renovate affected devices and systems, and costs for reporting requirements to state and federal agencies. From its inception through December 31, 1999, the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1999 Annual Report
Year 2000 program costs, recognized primarily as expense, amounted to approximately $5 million.
FINANCIAL CONDITION
Overview
The principal change in Mississippi Power's financial condition during 1999 was the addition of approximately $76 million to utility plant. Funding for these additions and other capital requirements were derived primarily from operations. The Statements of Cash Flows provide additional details.
Financing Activity
In 1999, the Company sold $9.4 million of pollution control bonds. Additionally, the Company retired and reissued unsecured debt of $50 million. See the Statements of Cash Flows for further details.
Composite financing rates have remained relatively flat for the years 1997 through 1999. As of year-end for each year respectively, the composite rates were as follows:
1999 1998 1997 ---------------------------- Composite interest rate on long-term debt 6.19% 6.14% 6.16%
Composite preferred stock dividend rate 6.33% 6.33% 6.33%
Composite interest rate on preferred securities 7.75% 7.75% 7.75% ------------------------------------------------------------
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility. It is anticipated that the total project will cost approximately $406 million, and upon project completion in mid 2001, the Company intends to lease the facility for an initial term of approximately 10 years. It is anticipated that the annual lease payments will approximate $32 million during the initial term.
Capital Structure
At year-end 1999, the Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, decreased from 52.1 percent in 1998, to 50.2 percent.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $199 million ($84 million in 2000, $54 million in 2001, and $61 million in 2002). The major emphasis within the construction program will be on the upgrade of existing facilities.
Revisions to projected construction expenditures may be necessary because of factors such as changes in business conditions, revised load projections, the availability and cost of capital, changes in environmental regulations, and alternatives such as leasing.
Other Capital Requirements
In addition to the funds required for the Company's construction program, approximately $80.1 million will be required by the end of 2002 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
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action in the U.S. District Court against Alabama Power Company, Georgia Power Company and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously, and the Company's plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1999 Annual Report
The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly the Company's financial condition unless such costs can be recovered through regulated rates.
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 other subsidiaries of Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995 and 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 started in 2000, and all fossil-fired generating plants are now 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 currently uses emission allowances and increased fuel switching. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements. Compliance for Phase II and initial ozone non-attainment requirements increased total estimated construction expenditures by approximately $105 million. 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 provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In September 1998, the EPA issued the final regional nitrogen oxide rules to the states for implementation. 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. Mississippi is one of those new 15 states. The EPA's July 1997 standards and the September 1998 rule 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 any new standards will depend on the development and implementation of applicable regulations.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1999 Annual Report
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 was substantially remediated in 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 or other environmental concerns. The likelihood or outcome of such potential lawsuits cannot be determined at this time.
Sources of Capital
To meet short-term cash needs and contingencies, the Company had at December 31, 1999 approximately $173 thousand of cash and cash equivalents and approximately $104.3 million of unused committed credit agreements. The Company had $57.5 million of short term notes payable outstanding at year end 1999.
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 1998 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 high enough to permit, at present interest rate levels, any foreseeable security sales. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.
Cautionary Statement Regarding Forward-Looking Information
This annual report, 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 1999 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company is a wholly owned subsidiary of Southern Company, which is the parent company of five integrated Southeast utilities, Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Energy Solutions, and other direct and indirect subsidiaries. The integrated Southeast utilities -- Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four southeastern states. Contracts among the integrated Southeast utilitis related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). The system service company provides, at cost, specialized services to Southern Company and the subsidiary companies. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related servies to utilities and industrial companies in selected countries around the world. Southern Energy businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. 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.
Prior years' data presented in the financial statements have been reclassified to conform with the current year presentation.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $45.5 million, $43.9 million, and $34.5 million during 1999, 1998, and 1997, respectively.
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 at December 31 relate to:
1999 1998 ------------------------- (in thousands) Deferred income tax charges $ 21,557 $ 22,697 Vacation pay 5,218 4,717 Workforce reduction plan of 1997 - 12,748 Premium on reacquired debt 8,154 9,304 Deferred environmental costs 323 1,500 Property damage reserve (3,082) (910) Deferred income tax credits (34,765) (37,277) Other, net (672) (2,538) - ---------------------------------------------------------------- Total $ (3,267) $ 10,241 ================================================================
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
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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 and Fuel Costs
The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Mississippi, and to wholesale customers in the Southeast.
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 plant in service is provided primarily by using composite straight-line rates which approximated 3.3 percent in 1999. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -- together with the cost of removal, less salvage -- is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of 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.
Property, Plant and Equipment
Property, plant, and equipment is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction, if applicable. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense except for the maintenance of coal cars and a portion of the railway track maintenance, which are charged to fuel stock. The cost of replacements of property (exclusive of minor items of property) is capitalized.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Financial Instruments
The Company's financial instruments for which the carrying amount did not equal fair value at December 31 were as follows:
Carrying Fair Amount Value --------------------------- (in millions) Long-term debt At December 31, 1999 $353 $334 At December 31, 1998 $343 $348 Capital trust preferred securities: At December 31, 1999 $35 $30 At December 31, 1998 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.
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Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when used or installed.
Provision for Property Damage
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 accrues for the cost of such damage by charging expense and crediting an accumulated provision. The cost of repairing damage resulting from such events that individually exceed $50 thousand is charged to the accumulated provision. Effective November 1999, an order from the MPSC increased the maximum Property Damage Reserve from $18 million to $23 million and allows an annual accrual of up to $4.6 million. In 1999, the Company provided for such costs by charges to income of $4.4 million, which is an increase of $2.9 million when compared to the $1.5 million allowed in both 1998 and 1997. As of December 31, 1999, the accumulated provision amounted to $3.1 million.
2. RETIREMENT BENEFITS
Mississippi Power has a defined benefit, trusteed, pension plan that covers substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all these employees may become eligible for such benefits when they retire. The Company funds trusts to the extent required by the MPSC. The measurement date for plan assets and obligations is September 30 for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations ---------------------------- 1999 1998 - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $142,807 $132,131 Service cost 4,415 3,848 Interest cost 9,377 9,613 Benefits paid (8,050) (7,845) Actuarial (gain) loss and employee transfers (8,619) 5,060 - ----------------------------------------------------------------- Balance at end of year $139,930 $142,807 =================================================================
Plan Assets ---------------------------- 1999 1998 - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $198,100 $207,457 Actual return on plan assets 33,216 1,252 Benefits paid (8,050) (7,845) Employee transfers (1,779) (2,764) - ----------------------------------------------------------------- Balance at end of year $221,487 $198,100 =================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1999 1998 - -------------------------------------------------------------------- (in thousands) Funded status $ 81,557 $ 55,293 Unrecognized transition obligation (3,814) (4,359) Unrecognized prior service cost 4,991 5,405 Unrecognized net gain (80,246) (56,590) - -------------------------------------------------------------------- Prepaid asset (liability) recognized in the Balance Sheets $2,488 $ (251) ====================================================================
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Components of the plans' net periodic cost were as follows:
1999 1998 1997 - ------------------------------------------------------------------ (in thousands) Service cost $ 4,415 $ 3,848 $ 4,015 Interest cost 9,377 9,613 9,407 Expected return on plan assets (14,681) (13,817) (12,805) Recognized net gain (1,721) (1,956) (1,729) Net amortization (131) (131) (119) - ------------------------------------------------------------------ Net pension income $(2,741) $ (2,443) $ (1,231) ==================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations ---------------------------- 1999 1998 - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $47,260 $43,417 Service cost 982 806 Interest cost 3,105 3,162 Benefits paid (2,256) (2,302) Actuarial loss and employee transfers (3,701) 2,177 - ----------------------------------------------------------------- Balance at end of year $45,390 $47,260 =================================================================
Plan Assets ---------------------------- 1999 1998 - ----------------------------------------------------------------- (in thousands) Balance at beginning of year $12,779 $12,189 Actual return on plan assets 1,818 176 Employer contributions 2,657 2,716 Benefits paid (2,256) (2,302) - ----------------------------------------------------------------- Balance at end of year $14,998 $12,779 =================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
1999 1998 - -------------------------------------------------------------------- (in thousands) Funded status $(30,392) $(34,481) Unrecognized transition obligation 4,621 4,967 Unrecognized net loss (gain) (3,406) 1,010 Fourth quarter contributions 931 577 - -------------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(28,246) $(27,927) ====================================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997 - ------------------------------------------------------------------ (in thousands) Service cost $ 981 $ 806 $ 867 Interest cost 3,105 3,162 2,922 Expected return on plan assets (1,100) (989) (815) Recognized net (gain) loss - - (7) Net amortization 346 346 362 - ------------------------------------------------------------------ Net postretirement cost $3,332 $3,325 $3,329 ==================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits were:
1999 1998 --------------------------------------------------------------- Discount 7.50% 6.75% Annual salary increase 5.00 4.25 Long-term return on plan assets 8.50 8.50 ---------------------------------------------------------------
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An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 7.74 percent for 1999, decreasing gradually to 5.50 percent through the year 2005 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would increase the accumulated benefit obligation and the service and interest cost components at December 31, 1999 as follows:
1 Percent 1 Percent Increase Decrease - ----------------------------------------------------------------- (in thousands) Benefit obligation $2,983 $(2,551) Service and interest costs 258 (219) - -----------------------------------------------------------------
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 was 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. At December 31, 1999, the Company has completely amortized the $18.2 million.
3. LITIGATION AND REGULATORY MATTERS
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action in the U.S. District Court against Alabama Power Company, Georgia Power Company and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously, and the Company's plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly the Company's financial condition unless such costs can be recovered through regulated rates.
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 Power'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 1999, 1998 or 1997.
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
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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. In 1998 and 1999, the Company's ECO filing resulted in a small decrease in customer prices in each year. The Company filed its 2000 ECO Plan in January, and if approved as filed, will result in a small decrease in customer prices.
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 has been investigated and substantially remediated. The remedial plan was approved by the Mississippi Department of Environmental Quality. Remediation of this site began in 1999 and is scheduled to be completed in early 2000. The Company expects the total remediation costs to be approximately $2.0 million, with approximately $1.5 million recovered from other parties and the balance through the ECO Plan. The Company recovers such costs under the ECO Plan as they are incurred, as provided for in the Company's 1995 ECO Order. As of December 31, 1999, the balance in the liability and regulatory asset accounts was $0.3 million.
Approval for New Capacity
In January 1998, the Company was granted a Certificate of Public Convenience and Necessity by the MPSC to build approximately 1,000 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 5, Financing and Commitments). 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 $84 million in 2000, $54 million in 2001, and $61 million in 2002. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; revised load growth estimates; changes in environmental regulations; increasing costs of labor, equipment and materials; and cost of capital. Significant construction will continue related to transmission and distribution facilities, and the upgrading of generating plants.
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 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.
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility. It is anticipated that the total project will cost approximately $406 million, and upon project completion in mid 2001, the Company intends to lease the facility for an initial term of approximately 10 years. It is anticipated that the annual lease payments will approximate $32 million during the initial term.
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Bank Credit Arrangements
At December 31, 1999, Mississippi Power had total committed credit agreements with banks for $104.3 million. At year-end 1999, the unused portion of these committed credit agreements was $104.3 million. These credit agreements expire at various dates 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 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, 1999, the Company had $57.5 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 Corp.) 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 1999 use fees collected under this agreement, net of related expenses, amounted to approximately $3 million each year, and are included within Other Income in the Statements of Income.
In 1989, 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 stock, was $2.8 million in 1999, $2.8 million in 1998, and $2.0 million in 1997. The Company's annual lease payments for 2000 through 2004 will average approximately $1.8 million and after 2004, lease payments total in aggregate approximately $14.4 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, 1999, were as follows:
Year Fuel - ----------- ---------- (in millions) 2000 $147 2001 121 2002 124 2003 125 2004 9 2005 - 2026 115 - --------------------------------------------------- Total commitments $641 - ---------------------------------------------------
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. For the years ended 1999, 1998 and 1997 Mississippi Power exercised its options to purchase 250 megawatts, 300 megawatts and 250 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. In 1999, Mississippi Power exercised its option to purchase 400 megawatts of summer peaking capacity for the year 2000.
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6. JOINT OWNERSHIP AGREEMENTS
Mississippi Power and Alabama Power own as tenants in common Units 1 and 2 at Plant Greene County located in Alabama; and Mississippi Power and Gulf Power own as tenants in common Units 1 and 2 at Plant Daniel located in Mississippi.
At December 31, 1999, 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% $61,050 $29,636
Daniel Units 1 and 2 1,000 50% $225,761 $103,213 ------------------------------------------------------------------
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 utility affiliates of Southern Company have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The Company's capacity revenues under these agreements were not material during the periods reported.
8. INCOME TAXES
At December 31, 1999, the tax-related regulatory assets and liabilities were $22 million and $35 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:
1999 1998 1997 ---------------------------------- (in thousands) Total provision for income taxes Federal -- Current $33,379 $20,500 $27,651 Deferred --current year 3,747 7,007 8,171 --reversal of prior years (7,720) 2,435 (9,236) ----------------------------------------------------------------- 29,406 29,942 26,586 ----------------------------------------------------------------- State -- Current 4,881 2,544 5,537 Deferred --current year 738 1,568 1,756 --reversal of prior years (908) 610 (2,499) ----------------------------------------------------------------- 4,711 4,722 4,794 ----------------------------------------------------------------- Total 34,117 34,664 31,380 =================================================================
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:
1999 1998 ----------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $154,698 $153,768 Basis differences 8,967 9,642 Other 23,108 26,038 --------------------------------------------------------------- Total 186,773 189,448 --------------------------------------------------------------- Deferred tax assets: Other property basis differences 21,003 22,391 Pension and other benefits 9,608 9,441 Property insurance 3,419 1,526 Unbilled fuel 4,846 2,080 Other 11,071 14,406 --------------------------------------------------------------- Total 49,947 49,844 --------------------------------------------------------------- Net deferred tax liabilities 136,826 139,604 Portion included in current assets, net 2,738 4,248 --------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $139,564 $143,852 ===============================================================
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NOTES (continued) Mississippi Power Company 1999 Annual Report
Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $1.2 million in 1999, 1998, and 1997. At December 31, 1999, 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:
1999 1998 1997 ---------------------------------- Federal statutory rate 35.00% 35.00% 35.00% State income tax, net of federal deduction 3.37 3.34 3.51 Non-deductible book depreciation .77 .47 .47 Other (1.62) (1.04) (3.60) ------------------------------------------------------------------ Effective income tax rate 37.52% 37.77% 35.38% ==================================================================
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.
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 the Company of the Trusts' payment obligations 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:
1999 1998 ------------------- (in thousands) Bond improvement fund requirement $1,000 $1,000 Less: Portion to be satisfied by certifying property additions 1,000 1,000 --------------------------------------------------------------- Cash sinking fund requirement - - Redemptions of first mortgage bonds - - Current portion of other long-term debt 30,000 50,000 Pollution control bond cash sinking fund requirements 20 20 --------------------------------------------------------------- Total $30,020 $50,020 ===============================================================
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, 1999, 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.
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12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1999 and 1998 are as follows:
Net Income After Dividends Operating Operating On Preferred Quarter Ended Revenues Income Stock - -------------------------------------------------------------------- (in thousands) March 1999 $122,435 $18,122 $7,193 June 1999 158,590 31,289 14,953 September 1999 201,594 51,609 27,313 December 1999 150,385 18,736 5,350
March 1998 $122,156 $20,299 $8,388 June 1998 156,612 30,126 13,713 September 1998 191,699 50,948 28,309 December 1998 124,664 13,498 4,696 - --------------------------------------------------------------------
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
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MANAGEMENT'S REPORT Savannah Electric and Power Company 1999 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 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 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 16, 2000
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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, 1999 and 1998, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-181 through II-194) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP Atlanta, Georgia February 16, 2000
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 1999 totaled $23.1 million, representing a decrease of $0.6 million or 2.4 percent from the prior year. Earnings were down primarily due to lower non-operating revenues.
In 1998, earnings were $23.6 million, representing a $0.2 million, or 0.9 percent decrease from the prior year. This was principally the result of a decrease in other income, net.
Revenues
Total revenues for 1999 were $251.6 million, reflecting a 1.1 percent decrease when compared to 1998. The following table summarizes the factors affecting operating revenues for the past three years:
Increase (Decrease) From Prior Year -------------------------------------- 1999 1998 1997 -------------------------------------- Retail -- (in thousands) Growth and price changes $ 5,633 $ (479) $ 7,664 Weather (5,257) 8,336 (6,186) Fuel cost recovery and other (438) 15,012 (10,002) ----------------------------------------------------------------- Total retail (62) 22,869 (8,524) ----------------------------------------------------------------- Sales for resale-- Non-affiliates (1,153) 1,081 1,469 Affiliates 1,135 964 (1,078) ----------------------------------------------------------------- Total sales for resale (18) 2,045 391 ----------------------------------------------------------------- Other operating revenues (2,781) 3,264 336 ----------------------------------------------------------------- Total operating revenues $(2,861) $ 28,178 $ (7,797) ================================================================= Percent change (1.1)% 12.5% (3.3)% -----------------------------------------------------------------
Retail revenues were relatively unchanged in 1999 when compared to 1998. Reduced demand for energy in the industrial sector and a base rate decrease to the small business customers partially offset by increased demand in the residential and commercial sectors contributed to this variance.
In 1998, retail revenues increased by 10.4 percent over the prior year due primarily to unusually hot summer weather that resulted in increased energy sales to residential and commercial customers. A base rate decrease to the small business customer class, ordered by the Georgia Public Service Commission (GPSC), was effective in July 1998. See Note 3 to the financial statements for additional information.
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. Revenues from these sales were not material during the three-year period.
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 1999 and the percent change by year were as follows:
KWH Percent Change ------------ ----------------------------- 1999 1999 1998 1997 ------------ ----------------------------- (in millions)
Residential 1,579 2.6% 7.8% (1.9)% Commercial 1,288 4.2 6.9 1.3 Industrial 713 (20.7) 2.1 5.1 Other 133 1.1 5.3 (1.4) ------------ Total retail 3,713 (2.5) 6.0 0.8 Sales for resale-- Non-affiliates 51 (3.3) (43.5) 2.9 Affiliates 77 31.8 7.2 30.4 ------------ Total 3,841 (2.0)% 4.8 % 1.2 % =====================================================================
Total retail energy sales in 1999 were down by 2.5% from the prior year reflecting reduced energy sales of 20.7% to industrial customers due to the shut-down of one industrial customer's facilities in late 1998 and completed construction of a steam turbine unit by another industrial customer. These reductions were partially mitigated by increased energy sales of 2.6% and 4.2% to residential and commercial customers, respectively.
In 1998, total retail energy sales were up 6.0% over the prior year, reflecting the impact of the hotter-than-normal weather on energy sales to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1999 Annual Report
residential and commercial customers and high demand from an industrial customer.
Expenses
Total operating expenses for 1999 were $201.5 million, a slight increase of $1.2 million from the prior year due primarily to increases in purchased power from non- affiliates and depreciation and amortization. Purchased power from non-affiliates increased due principally to higher demand for energy and increased costs associated with these power purchases. Maintenance expenses decreased this year compared to 1998 due to repair costs in 1998 related to a major turbine dismantle inspection. Depreciation and amortization increased reflecting additional depreciation charges related to the GPSC's accounting order. See Note 3 to the financial statements for additional information on the GPSC's 1998 accounting order.
In 1998, total operating expenses were $200.3 million reflecting a $27.7 million increase from 1997. Major components of this increase included 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, however, were partially offset by a $6.4 million decrease in purchased power from affiliates. The increase in fuel expense was primarily attributed 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.
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:
1999 1998 1997 -------------------------- Total energy supply (millions of KWHs) 4,039 4,182 3,964 Sources of energy supply (percent) -- Coal 45 42 34 Oil 2 1 - Gas 10 12 5 Purchased Power 43 45 61 Total average cost of energy supply (cents) 2.44 2.35 2.02 - -----------------------------------------------------------------
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors 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).
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1999 Annual Report
Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new short and long-term contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area.
The electric utility industry in the United States is currently undergoing a period of dramatic change as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access the Company's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. The Company is positioning the business to meet the challenge of this major change in the traditional practice of selling electricity.
Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. As these initiatives materialize, the structure of the utility industry could radically change. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While 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 financial condition and results of operation. The Company is attempting to minimize or reduce its cost exposure.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
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 1998, the GPSC issued a four-year accounting order settling its review of the Company's earnings. See Note 3 to the financial statements for additional information.
On December 20, 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. To facilitate the development of RTOs, the FERC will convene regional conferences for utilities, customers, and other members of the public to discuss the formation of RTOs. In addition to participating in the regional conferences, utilities owning transmission systems, including the Company, are required to make a filing by October 15, 2000. The filing must contain either a proposal for RTO participation or a description of the efforts made to participate in an RTO, the reasons for non-participation, any obstacles to participation, and any plans for further work toward participation. The RTOs that are proposed in the filings should be operational by December 15, 2001. The Company is evaluating this issue and formulating its response. The outcome of this matter cannot now be determined.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1999 Annual Report
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 statement as incurred. At December 31, 1999, 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, 1999, 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 January 1, 2001. 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.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and other date sensitive devices to function correctly in the Year 2000 was successful. There were no material incidents reported and no disruption of electric service within the service area. There were no reports of significant events regarding third parties that impacted revenues or expenses.
Original projected total costs for Year 2000 readiness were approximately $1.2 million. Final projected costs are $1.3 million of which $0.1 million is projected to be spent in 2000. These costs include labor necessary to identify, test, and renovate affected devices and systems, and costs for reporting requirements to state and federal agencies. From its inception through December 31, 1999, the Year 2000 program costs, recognized as expense, amounted to $1.2 million.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1999 was the addition of $29.8 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, 1999, the Company's capital structure consisted of 48.3 percent common stockholders' equity, 11.0 percent trust preferred securities, and 40.7 percent long-term debt, excluding amounts due within one year. The Company's long-term financial objective for capitalization ratios is to maintain a capital structure of common stockholders' equity at 48 percent, preferred securities at 10 percent and debt at 42 percent.
Maturities and retirements of long-term debt were $16 million in 1999, $30 million in 1998 and $14 million in 1997. Included in the 1999 maturities and retirements is the purchase by Savannah Electric of all $15 million outstanding of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.
During 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. Also in 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1999 Annual Report
The composite interest rates and dividend rates for the years 1997 through 1999 as of year-end were as follows:
1999 1998 1997 ------------------------------- Composite interest rates on long-term debt 6.4% 6.5% 6.9% Preferred stock dividend rate -% -% 6.6% Trust preferred securities dividend rate 6.9% 6.9% -% - -----------------------------------------------------------------
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $91.8 million ($25.6 million in 2000, $30.4 million in 2001, and $35.8 million in 2002). Actual construction costs may vary from this estimate because of factors such as changes in: business conditions; environmental regulations; load projections; the cost and efficiency of construction labor, equipment and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Construction 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 $31.8 million will be needed by the end of 2002 for maturities of long-term debt and present sinking fund requirements.
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. Construction expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $2 million for Savannah Electric.
For Phase II sulfur dioxide compliance, Southern Company currently uses emission allowances and increased fuel switching. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired plants as necessary to meet Phase II limits and ozone non-attainment requirements. Compliance for Phase II and initial ozone non-attainment requirements increased total estimated construction expenditures by approximately $105 million. 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.
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action in the U.S. District Court against Alabama Power, Georgia Power and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously and the Company's Plant Kraft. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1999 Annual Report
day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
In July 1997, the 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 final rule affects 22 states including Georgia. The EPA's July 1997 standards and the September 1998 rule are being challenged in the courts by several states and industry groups. Implementation of the final state rules for these three initiatives could require substantial further reductions in nitrogen oxide and sulfur dioxide emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: 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.
Sources of Capital
At December 31, 1999, the Company had $6.6 million of cash and $26.2 million of unused short-term and revolving credit arrangements with banks to meet its short-term cash needs and to provide additional interim funding for the Company's construction program. Revolving credit arrangements total $20 million, of which $10 million expires December 31, 2001 and $10 million expires December 31, 2002.
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 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1999 Annual Report
Cautionary Statement Regarding Forward-Looking Information
Savannah Electric and Power Company's 1999 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; 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 Savannah Electric and Power Company 1999 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Savannah Electric and Power Company (the Company), is a wholly owned subsidiary of Southern Company, which is the parent company of five integrated Southeast utilities, Southern Company Services, Inc. (SCS), 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 integrated Southeast utilities provide electric service in four states. Contracts among the integrated Southeast utilities--related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. SCS, a system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy acquires, develops, builds, owns and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Southern Energy businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company also is subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). The Company follows 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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $16.0 million, $15.3 million, and $13.3 million during 1999, 1998, and 1997, respectively.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to:
1999 1998 -------------------------- (in thousands) Deferred income tax charges $ 16,063 $ 17,130 Premium on reacquired debt 8,385 8,570 Deferred income tax credits (19,687) (21,349) Storm damage reserves (1,392) (1,580) Accelerated depreciation (3,000) (1,000) - --------------------------------------------------------------- Total $ 369 $ 1,771 ===============================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
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NOTES (continued) Savannah Electric and Power Company 1999 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 of southeastern Georgia, and to wholesale customers in the Southeast.
Revenues are accrued for service rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current regulated rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than 1 percent of revenues.
In 1999, the GPSC approved increases of slightly over three-tenths of a cent per kilowatt-hour in the Company's fuel allowance.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.0 percent in 1999, and 2.9 percent in 1998 and 1997. 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 6.26 percent in 1999, 8.00 percent in 1998 and 9.24 percent in 1997.
Property, Plant and Equipment
Property, plant and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is capitalized.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
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NOTES (continued) Savannah Electric and Power Company 1999 Annual Report
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, 1999 $142 $136 At December 31, 1998 158 162 Trust preferred securities: At December 31, 1999 $40 $31 At December 31, 1998 40 40
The fair values for long-term debt and preferred securities were based on either closing market prices or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the 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 required by the GPSC. The measurement date for plan assets and obligations is September 30 of 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 --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $59,207 $51,720 Service cost 1,746 1,495 Interest cost 3,893 3,806 Benefits paid (3,414) (3,392) Actuarial (gain) loss and employee transfers (1,856) 4,343 Amendments 385 1,235 - --------------------------------------------------------------- Balance at end of year $59,961 $59,207 ===============================================================
Plan Assets --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $49,630 $50,630 Actual return on plan assets 8,168 171 Employer contributions - 2,464 Benefits paid (3,414) (3,392) Employee transfers 96 (243) - --------------------------------------------------------------- Balance at end of year $54,480 $49,630 ===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1999 1998 - ----------------------------------------------------------------- (in thousands) Funded status $(5,481) $(9,577) Unrecognized transition obligation 178 266 Unrecognized prior service cost 2,996 2,874 Unrecognized net loss 3,508 9,718 - ----------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 1,201 $ 3,281 =================================================================
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NOTES (continued) Savannah Electric and Power Company 1999 Annual Report
Components of the plans' net periodic cost were as follows:
1999 1998 1997 - ----------------------------------------------------------------- (in thousands) Service cost $1,746 $1,495 $1,393 Interest cost 3,893 3,806 3,556 Expected return on plan assets (4,063) (3,992) (3,782) Recognized net loss 152 2 475 Net amortization 352 334 280 - ----------------------------------------------------------------- Net pension cost $2,080 $1,645 $1,922 =================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $23,556 $20,899 Service cost 404 348 Interest cost 1,549 1,528 Benefits paid (756) (839) Actuarial (gain) loss and employee transfers (1,849) 1,620 - --------------------------------------------------------------- Balance at end of year $22,904 $23,556 ===============================================================
Plan Assets --------------------------- 1999 1998 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $3,803 $3,110 Actual return on plan assets 476 85 Employer contributions 1,731 1,447 Benefits paid (756) (839) - --------------------------------------------------------------- Balance at end of year $5,254 $3,803 ===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
1999 1998 - --------------------------------------------------------------- (in thousands) Funded status $(17,650) $(19,753) Unrecognized transition obligation 6,419 6,913 Unrecognized net loss 3,311 5,444 Fourth quarter contributions 1,336 1,152 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(6,584) $ (6,244) ===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997 - ---------------------------------------------------------------- (in thousands) Service cost $ 404 $ 348 $ 319 Interest cost 1,549 1,528 1,499 Expected return on plan assets (345) (276) (211) Recognized net loss 152 104 125 Net amortization 494 494 494 - ---------------------------------------------------------------- Net postretirement cost $2,254 $2,198 $2,226 ================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits were:
1999 1998 - --------------------------------------------------------------- Discount 7.50% 6.75% Annual salary increase 5.00 4.25 Long-term return on plan assets 8.50 8.50 - ---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 7.74 percent for 1999, decreasing gradually to 5.50 percent through the year 2005, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 1999 as follows:
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NOTES (continued) Savannah Electric and Power Company 1999 Annual Report
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in thousands) Benefit obligation $1,316 $(1,244) Service and interest costs 106 (100) ===============================================================
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 $0.5 million for 1999, and $0.4 million for 1998 and 1997.
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.
3. REGULATORY MATTERS
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action in the U.S. District Court against Alabama Power, Georgia Power and the system service company. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The EPA concurrently issued to the integrated Southeast utilities a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously and the Company's Plant Kraft. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. Southern Company believes that its integrated utilities complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Rates to retail customers served by the Company are regulated by the GPSC. As part of the Company's rate settlement in 1992, it was informally agreed that the Company's earned rate of return on common equity should be 12.95 percent.
In 1998, the GPSC approved a four-year accounting order for the Company. Under this order, the Company will reduce the electric rates of its small business customers by approximately $11 million over 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 $25.6 million in 2000, $30.4 million in 2001, and $35.8 million in 2002. 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.
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NOTES (continued) Savannah Electric and Power Company 1999 Annual Report
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 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 1999, unused credit arrangements with six banks totaled $26.2 million and expire at various times during 2000.
The Company has revolving credit arrangements of $20 million, of which $10 million expires December 31, 2001 and $10 million expires December 31, 2002. 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.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into long-term commitments for the procurement of fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. The Company has fuel commitments of $15 million and $9 million for 2000 and 2001, respectively.
In 1999, the Company entered into a purchased power agreement for 200 megawatts of capacity from Georgia Power Company's combined cycle combustion turbine units currently under construction at Plant Wansley and due to begin operation in 2002.
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.5 million for 1999, $1.1 million for 1998 and $1.2 million for 1997.
At December 31, 1999, estimated future minimum lease payments for noncancelable operating leases were as follows:
Rental Commitments -------------------- (in thousands) 2000 $ 483 2001 483 2002 483 2003 483 2004 483 2005 and thereafter $6,485 - -------------------------------------------------------------
6. INCOME TAXES
At December 31, 1999, tax-related regulatory assets and liabilities were $16.1 million and $19.7 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.
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NOTES (continued) Savannah Electric and Power Company 1999 Annual Report
Details of income tax provisions are as follows:
1999 1998 1997 -------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $12,968 $ 6,763 $ 9,743 Deferred -- current year 354 8,377 4,522 -- reversal of prior years (3,683) (2,565) (1,381) - ------------------------------------------------------------------ 9,639 12,575 12,884 - ------------------------------------------------------------------ State -- Currently payable 2,193 1,327 1,603 Deferred -- current year (34) 1,174 569 -- reversal of prior years 10 25 130 - ------------------------------------------------------------------ 2,169 2,526 2,302 - ------------------------------------------------------------------ Total $11,808 $15,101 $15,186 ==================================================================
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:
1999 1998 -------------------- Deferred tax liabilities: (in thousands) Accelerated depreciation $73,400 $75,187 Property basis differences 6,917 7,591 Other 12,031 10,187 - ---------------------------------------------------------------- Total 92,348 92,965 - ---------------------------------------------------------------- Deferred tax assets: Pension and other benefits 6,925 4,892 Other 2,935 2,828 - ---------------------------------------------------------------- Total 9,860 7,720 - ---------------------------------------------------------------- Net deferred tax liabilities 82,488 85,245 Portions included in current assets, net (2,170) (2,467) - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $80,318 $82,778 ================================================================
Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $0.7 million in 1999, 1998 and 1997. At December 31, 1999, 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:
1999 1998 1997 ----------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of federal income tax benefit 4 4 4 Other (5) (2) (2) ---------------------------------------------------------------- Effective income tax rate 34% 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.
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 the Trust are $40 million aggregate principal amount of the Company's 6.85% junior subordinated notes due December 31, 2028.
The Company considers that the mechanisms and obligations relating to the 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.
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NOTES (continued) Savannah Electric and Power Company 1999 Annual Report
Maturities and retirements of long-term debt were $16 million in 1999, $30 million in 1998 and $14 million in 1997. Included in the 1999 maturities and retirements is the purchase by Savannah Electric of all $15 million outstanding of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.
In 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.
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:
1999 1998 --------------------- (in thousands) Bond sinking fund requirement $650 $800 Less: Portion to be satisfied by certifying property additions 650 - Reacquired bonds and/or cash deposits - 800 - ------------------------------------------------------------------- Cash sinking fund requirement - - Other long-term debt maturities 704 689 - ------------------------------------------------------------------- Total $704 $689 ===================================================================
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 1999 and 1998. It is anticipated that the 2000 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2004 applicable to long-term debt are as follows: $0.7 million in 2000; $30.6 million in 2001; $0.5 million in 2002; $20.4 million in 2003; and $0.4 million in 2004.
9. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Indenture contains certain limitations on the payment of cash dividends on common stock. At December 31, 1999, 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 1999 and 1998 are as follows (in thousands):
Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock - ------------------------------------------------------------------
March 1999 $47,098 $ 5,637 $ 1,209 June 1999 61,692 12,495 5,268 September 1999 91,849 27,081 13,705 December 1999 50,955 4,850 2,901
March 1998 $48,381 $ 8,277 $ 2,426 June 1998 69,616 17,269 7,807 September 1998 84,224 24,777 12,518 December 1998 52,234 3,824 893 - ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
The quarterly operating income information above has been reclassified to reflect the Company's current presentation of income tax expense.
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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 2000 annual meeting of stockholders. The ages of directors and executive officers in Item 10 set forth below are as of December 31, 1999.
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 60 Served as Director since 3-1-89
Whit Armstrong (2) Age 52 Served as Director since 9-24-82
David J. Cooper, Sr. (2) Age 54 Served as Director since 4-24-98
H. Allen Franklin (2) Age 55 Served as Director since 10-22-99
R. Kent Henslee (2) Age 64 Served as Director since 10-22-99
Carl E. Jones, Jr. (2) Age 59 Served as Director since 4-22-88
Patricia M. King (2) Age 54 Served as Director since 7-25-97
James K. Lowder (2) Age 50 Served as Director since 7-25-97
Wallace D. Malone, Jr. (2) Age 63 Served as Director since 6-22-90
Thomas C. Meredith (2) Age 58 Served as Director since 10-23-98
Mayer Mitchell (2) Age 66 Served as Director since 10-22-99
William V. Muse (2) Age 60 Served as Director since 2-26-93
John T. Porter (2) Age 68 Served as Director since 10-22-93
Robert D. Powers (2) Age 49 Served as Director since 1-24-92
Andreas Renschler (2) Age 41 Served as Director since 1-23-98
C. Dowd Ritter (2) Age 52 Served as Director since 7-25-97
James H. Sanford (2) Age 55 Served as Director since 8-1-83
John C. Webb, IV (2) Age 57 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 23, 1999) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Franklin, Mr. Henslee and Mr. Mitchell, whose elections were effective 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 or she 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 60 Served as Executive Officer since 3-1-89
Banks H. Farris Executive Vice President Age 64 Served as Executive Officer since 12-3-91
Michael D. Garrett Executive Vice President Age 50 Served as Executive Officer since 3-1-98
William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer Age 56 Served as Executive Officer since 12-3-91
C. Alan Martin Executive Vice President Age 51 Served as Executive Officer since 1-1-00
Jerry L. Stewart Senior Vice President Age 50 Served as Executive Officer since 7-23-99
(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 23, 1999) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Martin and Mr. Stewart, whose elections were effective on the dates 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 Chief Executive Officer of The Citizens Bank, Enterprise, Alabama. Also, President, Chairman of the Board and Chief Executive Officer of Enterprise Capital Corporation, 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.
H. Allen Franklin - President and Chief Operating Officer of SOUTHERN. He previously served as President and Chief Executive Officer of GEORGIA from 1994 to 1999. Director of GEORGIA and GULF.
R. Kent Henslee - Managing Partner of the law firm of Henslee, Robertson & Strawn, L.L.C., 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.
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.
Thomas C. Meredith - Chancellor of The University of Alabama System, Tuscaloosa, Alabama. Director of ATMOS Energy Corporation, Dallas, Texas.
Mayer Mitchell - President of Mitchell Brothers, Inc. (real estate and investments), Mobile, Alabama. Director of The Banc Corporation, Birmingham, Alabama.
William V. Muse - President of Auburn University, Auburn, Alabama.
John T. Porter - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama.
Robert D. Powers - President of The Eufaula Agency, Inc. (real estate and insurance), Eufaula, Alabama.
Andreas Renschler - President of Mcc smart Gmbh, Germany, a division of Daimler Chrysler.
C. Dowd Ritter - Chairman, President, Chief Executive Officer of AmSouth Bancorporation and AmSouth Bank, Birmingham, Alabama.
James H. Sanford - Chairman, HOME Place Farms Inc. (diversified farmers and ginners), Prattville, Alabama. President, Autauga Quality Cotton Association, Prattville, Alabama. Chairman of the Board, Sylvest Farms of Georgia, Inc., College Park, Georgia. Chairman of the Board, Sylvest Farms, Inc., Montgomery, Alabama.
John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber and wood products sales), Demopolis, Alabama.
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.
Michael D. Garrett - Executive Vice President - External Affairs since 1998. He previously served as Senior Vice President of External Affairs from February 1994 to March 1998. Responsible for governmental relations, environmental, public relations, economic development, corporate real estate and corporate services.
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.
C. Alan Martin - Executive Vice President - External Affairs since January 2000. He previously served as Executive Vice President and Chief Marketing Officer for SOUTHERN from 1998 to 1999. Responsible for governmental relations, environmental, public relations, economic development, corporate real estate and corporate services.
Jerry L. Stewart - Senior Vice President - Fossil and Hydro Generation since 1999. He previously served as Vice President of Fuel Services for SCS from 1992 to 1999. Responsible for providing overall management of the Fossil Generation, Hydro Generation, Power Generation Support and Fuels Department.
Involvement in certain legal proceedings. None.
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GEORGIA
Identification of directors of GEORGIA.
David M. Ratcliffe President and Chief Executive Officer Age 51 Served as Director since 6-1-99
Daniel P. Amos (1) Age 48 Served as Director since 5-21-97
Juanita P. Baranco (1) Age 50 Served as Director since 5-21-97
William A. Fickling, Jr. (1) Age 67 Served as Director since 4-18-73
H. Allen Franklin (1) Age 55 Served as Director since 1-1-94
L. G. Hardman III (1) Age 60 Served as Director since 6-25-79
James R. Lientz, Jr. (1) Age 56 Served as Director since 7-21-93
Zell Miller (1) Age 68 Served as Director since 2-17-99
G. Joseph Prendergast (1) Age 54 Served as Director since 1-20-93
Herman J. Russell (1) Age 69 Served as Director since 5-18-88
William Jerry Vereen (1) Age 59 Served as Director since 5-18-88
Carl Ware (1) (2) Age 56 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 19, 1999) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Ratcliffe, 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 or 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.
David M. Ratcliffe President, Chief Executive Officer and Director Age 51 Served as Executive Officer since 3-1-98
William C. Archer, III Executive Vice President - External Affairs Age 51 Served as Executive Officer since 4-6-95
Thomas A. Fanning Executive Vice President, Treasurer and Chief Financial Officer Age 42 Served as Executive Officer since 6-12-99
Gene R. Hodges Executive Vice President - Customer Operations Age 61 Served as Executive Officer since 11-19-86
Wayne T. Dahlke Senior Vice President - Power Delivery Age 58 Served as Executive Officer since 4-19-89
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James K. Davis Senior Vice President - Corporate Relations Age 59 Served as Executive Officer since 10-1-93
Robert H. Haubein Senior Vice President - Fossil/Hydro Power Age 59 Served as Executive Officer since 2-19-92
Leonard J. Haynes Senior Vice President - Marketing Age 49 Served as Executive Officer since 10-13-98
Fred D. Williams Senior Vice President - Resource Policy & Planning Age 55 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 19, 1999) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Fanning, 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 relationship None.
Business experience.
David M. Ratcliffe - President and Chief Executive Officer of GEORGIA since June 1999. He previously served as Executive Vice President, Treasurer and Chief Financial Officer from 1998 to 1999. Senior Vice President of External Affairs for SOUTHERN from 1995 to 1998. Director of Mississippi Chemical Corporation.
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.
William A. Fickling, Jr. - Chairman of the Board, Chief Executive Officer of Beech Street Corporation (provider of managed care services) since 1989. He previously served as President from 1995 to 1996.
H. Allen Franklin - President and Chief Operating Officer of SOUTHERN since 1999. He previously served as President and Chief Executive Officer of GEORGIA from 1994 to 1999. Director of ALABAMA and GULF.
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.
James R. Lientz, Jr. - President, Bank of America (formerly NationsBank) Mid-South Banking Group since 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 - President and Chief Operating Officer, Wachovia Corporation and Wachovia Bank, N.A., Winston Salem, North Carolina since April 1999. He previously served as Senior Executive Vice President, Wachovia Corporation, heading the banking division comprising the companies' consumer and corporate banking activities and Wachovia Bank, N.A. Director of Willamette Industries, Inc.
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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 Citizens Bancshares Corporation and National Service Industries, Atlanta, Georgia.
William Jerry Vereen - President, Treasurer, Chief Executive Officer, and Director 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 - Executive Vice President, The Coca-Cola Company since January 2000. He previously served as President, Africa Group, The Coca-Cola Company. Director of Charlotte-based Coca-Cola Bottling Co. Consolidated.
William C. Archer, III - Executive Vice President - External Affairs since September 1995. He previously served as Senior Vice President of External Affairs from April 1995 to September 1995. Vice President of 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, corporate concerns and economic development.
Thomas A. Fanning - Executive Vice President, Treasurer and Chief Financial Officer since June 1999. He previously served as Senior Vice President of Strategy for SOUTHERN from June 1998 to June 1999. Senior Vice President and Chief Information Officer for SOUTHERN from March 1995 to 1998. Vice President, Treasurer and Assistant Secretary for SCS from January to March 1995. Responsible for accounting, corporate secretary, finance and procurement.
Gene R. Hodges - Executive Vice President - Customer Operations, Power Delivery and Safety since 1992. Responsible for the northern and southern regions and power delivery, customer service, region safety and labor relations' areas.
Wayne T. Dahlke - Senior Vice President - Power Delivery since 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. Responsible for corporate relations and consumer affairs.
Robert H. Haubein - Senior Vice President - Fossil/ Hydro Power since 1994. Responsible for fossil/hydro power generation, labor relations, safety and health.
Leonard J. Haynes - Senior Vice President - Marketing since 1998. He previously served as 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 D. Williams - Senior Vice President - Resource Policy and Planning since 1997. He previously served as Senior Vice President of Wholesale Power Marketing from 1995 to 1997. Senior Vice President of 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 61 Served as Director since 2-1-94
Fred C. Donovan, Sr. (1) Age 59 Served as Director since 1-18-91
H. Allen Franklin (1) Age 55 Served as Director since 6-29-99
W. Deck Hull, Jr. (1) Age 67 Served as Director since 10-14-83
Joseph K. Tannehill (1) Age 66 Served as Director since 7-19-85
Barbara H. Thames (1) Age 59 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 29, 1999) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GULF acting solely in their capacities as such.
Identification of executive officers of GULF.
Travis J. Bowden President, Chief Executive Officer and Director Age 61 Served as Executive Officer since 2-1-94
Francis M. Fisher, Jr. Vice President - Power Delivery and Customer Operations Age 51 Served as Executive Officer since 5-19-89
John E. Hodges, Jr. Vice President - Marketing and Employee/External Affairs Age 56 Served as Executive Officer since 5-19-89
Robert G. Moore Vice President - Power Generation and Transmission Age 50 Served as Executive Officer since 7-25-97
Arlan E. Scarbrough Vice President - Finance Age 63 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 23, 1999) 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.
Fred C. Donovan, Sr. - President of Baskerville - Donovan, Inc., an architectural and engineering firm, Pensacola, Florida.
III-7
H. Allen Franklin - President and Chief Operating Officer of SOUTHERN since 1999. He previously served as President and Chief Executive Officer of GEORGIA from 1994 to 1999. Director of ALABAMA and GEORGIA.
W. Deck Hull, Jr. - President and Director of Hull Company, Panama City, Florida since 1997. He previously served as Vice Chairman of the SunTrust Bank, West Florida, Panama City, Florida from 1993 to 1997.
Joseph K. Tannehill - President, Chairman and Chief Executive Officer of Tannehill International Industries, Inc., Lynn Haven, Florida since 1991. Chairman and Chief Executive Officer of Merrick Industries, Inc., Lynn Haven, Florida since 1991. Director of Regions Bank of North Florida, Panama City, Florida.
Barbara H. Thames - Chief Operating Officer of West Florida Regional Medical Center, Pensacola, Florida (a-for-profit Healthcare Corporation) since 1998. 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 of 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 of Customer Operations from 1989 to 1996. Responsible for corporate communications, marketing, governmental 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 of Plant Bowen at GEORGIA. Responsible for the generation and transmission of electricity and bulk power marketing 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 51 Served as Director since 3-27-95
Edwin E. Downer (1) Age 68 Served as Director since 4-24-84
Robert S. Gaddis (1) Age 68 Served as Director since 1-21-86
Linda T. Howard (1) Age 56 Served as Director since 2-24-99
Aubrey K. Lucas (1) Age 65 Served as Director since 4-24-84
Malcolm Portera (1) Age 53 Served as Director since 4-6-99
George A. Schloegel (1) Age 59 Served as Director since 7-26-95
Philip J. Terrell (1) Age 46 Served as Director since 2-22-95
N. Eugene Warr (1) Age 64 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 6, 1999) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of MISSISSIPPI acting solely in their capacities as such.
Identification of executive officers of MISSISSIPPI.
Dwight H. Evans President, Chief Executive Officer and Director Age 51 Served as Executive Officer since 3-27-95
H. E. Blakeslee Vice President - Customer Services and Retail Marketing Age 59 Served as Executive Officer since 1-25-84
Mark S. Lynch Vice President - Power Generation and Delivery Age 46 Served as Executive Officer since 10-1-99
Don E. Mason Vice President - External Affairs and Corporate Services Age 58 Served as Executive Officer since 7-27-83
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer Age 47 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 (April 28, 1999) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Lynch, 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 MISSISSIPPI acting solely in their capacities as such.
III-9
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
Dwight H. Evans - President and Chief Executive Officer since 1995. He previously served as Executive Vice President of External Affairs of GEORGIA from 1989 to 1995.
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.
Linda T. Howard - President of Howard Industries, Inc., Laurel, Mississippi.
Aubrey K. Lucas - President Emeritus and Distinguished Professor of Higher Education at the University of Southern Mississippi, Hattiesburg, Mississippi.
Malcolm Portera - President, Mississippi State University, Starkville, Mississippi.
George A. Schloegel - President and Chief Executive Officer of Hancock Bank. President, Chief Executive Officer and Director of Hancock Bank Securities Corporation. Vice Chairman of Hancock Holding Company. Director of Hancock Bank of Mississippi and Hancock Bank of Louisiana.
Philip J. Terrell - Superintendent of Schools, Pass Christian Public School District, Pass Christian, Mississippi; and adjunct Professor of Education at William Carey College, Gulfport, Mississippi.
N. Eugene Warr - Retailer, Gulfport, Mississippi. Director of Coast Community Bank, formerly SouthTrust Bank of Mississippi, Biloxi, Mississippi.
H. E. Blakeslee - Vice President - Customer Services and Retail 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.
Mark S. Lynch - Vice President - Power Generation and Delivery since 1999. He previously served as President and Chief Executive Officer of Empresa Electrica del Norte Grande, S.A. from 1996 to 1999. 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.
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. He previously served as Director of Corporate Finance of SCS from 1994 to 1995. Responsible for accounting, secretary/treasury, corporate planning, procurement and information resources.
Involvement in certain legal proceedings. None.
III-10
SAVANNAH
Identification of directors of SAVANNAH.
G. Edison Holland, Jr. President and Chief Executive Officer Age 47 Served as Director since 7-15-97
Gus H. Bell (1) Age 62 Served as Director since 7-20-99
Archie H. Davis (1) Age 58 Served as Director since 2-18-97
Walter D. Gnann (1) Age 64 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 54 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 63 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 18, 1999) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Bell, 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 or she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of SAVANNAH acting solely in their capacities as such.
Identification of executive officers of SAVANNAH.
G. Edison Holland, Jr. President, Chief Executive Officer and Director Age 47 Served as Executive Officer since 7-15-97
Lewis A. Jeffers Vice President - Power Generation Age 44 Served as Executive Officer since 11-2-99
W. Miles Greer Vice President - Customer Operations and External Affairs Age 56 Served as Executive Officer since 11-20-85
Kirby R. Willis Vice President, Treasurer, Chief Financial Officer and Assistant Corporate Secretary Age 48 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 20, 1999 for the ensuing year, except for Mr. Jeffers 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 SAVANNAH acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships None.
Business experience.
G. Edison Holland, Jr. - President and Chief Executive Officer since 1997. He previously served as Vice President of Power Generation/Transmission and Corporate Counsel of GULF from 1995 to 1997. Served as a partner in the law firm of Beggs & Lane from 1979 to 1997. Director of SunTrust Bank of Savannah.
Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell and DeYoung, Inc., (specializing in environmental, industrial, structural, architectural and civil engineering), Savannah, Georgia. Director of SunTrust Bank of Savannah.
III-11
Archie H. Davis - President and Chief Executive Officer of The Savannah Bancorp and The Savannah Bank, N.A., Savannah, Georgia. Member of the Board of Directors of Thomaston Mills, Thomaston, Georgia..
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc., Springfield, Georgia.
Robert B. Miller, III - President of American Building Systems, Inc., Savannah, Georgia.
Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation. Director of First Union Bank of Georgia, First Union Bank of Savannah and Cerulean Corporation.
W. Miles Greer - Vice President - Customer Operations and External Affairs since 1998. He previously served as Vice President of Marketing and Customer Service from 1994 to 1998. Responsible for customer services, transmission and distribution, engineering, system operation and external affairs.
Lewis A. Jeffers - Vice President - Power Generation since 1999. He previously served as General Manager of Power Generation from February 1999 to November 1999; General Manager for Plants Smith and Scholz at GULF from May 1996 through January 1999; and Assistant General Manager at ALABAMA for Plant Barry from September 1993 to May 1996. Responsible for operations and maintenance of Plants Kraft, Riverside and McIntosh.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since 1994 and Assistant Corporate Secretary effective 1998. Responsible primarily for accounting, financial, labor relations, corporate services, corporate compliance, environmental and safety activities.
Involvement in certain legal proceedings. None
Section 16(a) Beneficial Ownership Reporting Compliance.
MISSISSIPPI's Mr. Lynch filed an Initial Statement of Beneficial Ownership of Equity Securities on Form 3, late.
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 1999 for each of the integrated Southeast utilities (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
See next page for footnotes.
III-13
III-14
III-15
III-16
III-17
III-18
III-19
III-20
AGGREGATED STOCK OPTION EXERCISES IN 1999 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information concerning options exercised during the year ending December 31, 1999, by the named executive officers and the value of unexercised options held by them as of December 31, 1999.
III-21
III-22
LONG-TERM INCENTIVE PLANS - AWARDS IN 1999
Long-Term Incentive Plans. The following table sets forth the long-term incentive plan awards made to the named executive officers for the performance period January 1, 1999 through December 31, 2002.
See next page for footnotes.
III-23
III-24
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Pension Plan Table. The following table sets forth the estimated annual pension benefits payable at normal retirement age under SOUTHERN's qualified Pension Plan, as well as supplemental benefits, based on the stated compensation and years of service with the SOUTHERN system for the named executives at ALABAMA, GEORGIA, GULF and MISSISSIPPI and Mr. Holland at SAVANNAH. Compensation for pension purposes is limited to the average of the highest three of the final 10 years' compensation -- base salary plus the excess of annual and long-term incentive compensation over 25 percent of base salary (reported under column titled "Salary", "Bonus", and "Long-Term Incentive Payouts" in the Summary Compensation 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, 1999, 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 $878,724 40 Banks H. Farris 429,312 40 William B. Hutchins, III 348,304 33 Michael D. Garrett 309,688 31 Jerry L. Stewart 257,848 26
III-25
GEORGIA Compensation Accredited Name Level Years of Service
H. Allen Franklin $967,132 28 David M. Ratcliffe 583,968 28 Robert H. Haubein, Jr. 344,444 32 Gene R. Hodges 356,788 35 Thomas A. Fanning 329,728 18 William C. Archer 323,200 28
GULF Compensation Accredited Name Level Years of Service
Travis J. Bowden1 $505,372 33 Arlan E. Scarbrough 257,876 36 John E. Hodges, Jr. 257,548 33 Francis M. Fisher, Jr. 240,780 28 Robert G. Moore 210,200 26
MISSISSIPPI Compensation Accredited Name Level Years of Service
Dwight H. Evans $448,124 28 H. E. Blakeslee 288,660 34 Andrew J. Dearman, III 229,043 24 Don E. Mason 281,516 33 Michael W. Southern 244,592 24 Mark S. Lynch 262,193 10
SAVANNAH Compensation Accredited Name Level Years of Service
G. Edison Holland, Jr.2 $336,428 16 W. Miles Greer 157,144 15 Kirby R. Willis 149,479 25 Lewis A. Jeffers 124,064 20
1 The number of accredited years of service includes 10 years credited to Mr. Bowden pursuant to a supplemental pension agreement. 2 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 the SOUTHERN Pension Plan. SAVANNAH also has in effect a supplemental executive retirement plan for certain of its executive employees. The plan is designed to provide participants with a supplemental retirement benefit, which, in conjunction with social security and benefits under SOUTHERN's qualified pension plan, will equal 70 percent of the highest three of the final 10 years' average annual earnings (excluding incentive compensation).
The following table sets forth the estimated combined annual pension benefits under SOUTHERN's pension and SAVANNAH's supplemental executive retirement plans in effect during 1999 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 84,000 150,000 105,000 105,000 105,000 180,000 126,000 126,000 126,000 210,000 147,000 147,000 147,000 260,000 182,000 182,000 182,000 280,000 196,000 196,000 196,000 300,000 210,000 210,000 210,000 320,000 224,000 224,000 224,000 340,000 238,000 238,000 238,000
III-27
Compensation of Directors.
Standard Arrangements. The following table presents compensation paid to the directors, during 1999 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, 1999 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 still employed by SOUTHERN or one of its subsidiaries, Mr. Franklin 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. GEORGIA assigned this agreement to SCS effective July 8, 1999.
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.
- ------------------------------------------------------------------------------- Amount and Name and Address Nature of Percent of Beneficial Beneficial of Title of Class Owner Ownership Class - ------------------------------------------------------------------------------- Common Stock The Southern Company 100% 270 Peachtree Street, N.W. Atlanta, Georgia 30303
Registrants: ALABAMA 5,608,955 GEORGIA 7,761,500 GULF 992,717 MISSISSIPPI 1,121,000 SAVANNAH 10,844,635
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, 1999. 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, 1999.
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2) - ------------------ -------------- --------------------------
ALABAMA
Whit Armstrong SOUTHERN Common 17,972
David J. Cooper, Sr. SOUTHERN Common 1,191
H. Allen Franklin SOUTHERN Common 220,337
Elmer B. Harris SOUTHERN Common 260,741
R. Kent Henslee SOUTHERN Common 4,019
Carl E. Jones, Jr. SOUTHERN Common 12,249
Patricia M. King SOUTHERN Common 306
James K. Lowder SOUTHERN Common 6,241
III-30
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2) - ------------------ -------------- --------------------------
Wallace D. Malone, Jr. SOUTHERN Common 627
Thomas C. Meredith SOUTHERN Common 416
Mayer Mitchell SOUTHERN Common 19
William V. Muse SOUTHERN Common 726
John T. Porter SOUTHERN Common 1,181
Robert D. Powers SOUTHERN Common 726
Andreas Renschler SOUTHERN Common 1,223
C. Dowd Ritter SOUTHERN Common 306
James H. Sanford SOUTHERN Common 658
John C. Webb, IV SOUTHERN Common 12,925
Banks H. Farris SOUTHERN Common 43,485
Michael D. Garrett SOUTHERN Common 18,216
William B. Hutchins, III SOUTHERN Common 59,771
C. Alan Martin SOUTHERN Common 5,320
Jerry L. Stewart SOUTHERN Common 24,221
The directors, nominees, and executive officers as a group SOUTHERN Common 692,874
GEORGIA
Daniel P. Amos SOUTHERN Common 297
Juanita P. Baranco SOUTHERN Common 297
W. A. Fickling, Jr. SOUTHERN Common 1,245
III-31
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2) - ------------------ -------------- --------------------------
H. Allen Franklin SOUTHERN Common 220,337
L. G. Hardman III SOUTHERN Common 17,422
James R. Lientz, Jr. SOUTHERN Common 1,271
Zell Miller SOUTHERN Common 373
G. Joseph Prendergast SOUTHERN Common 1,331
Herman J. Russell SOUTHERN Common 2,962
W. J. Vereen SOUTHERN Common 5,628
Carl Ware SOUTHERN Common 800
William C. Archer, III SOUTHERN Common 27,794
Thomas A. Fanning SOUTHERN Common 23,726
Robert H. Haubein, Jr. SOUTHERN Common 40,381
Gene R. Hodges SOUTHERN Common 56,540
David M. Ratcliffe SOUTHERN Common 95,158
The directors, nominees and executive officers as a group SOUTHERN Common 629,177
GULF
Travis J. Bowden SOUTHERN Common 29,368
Fred C. Donovan, Sr. SOUTHERN Common 526
H. Allen Franklin SOUTHERN Common 220,337
W. Deck Hull, Jr. SOUTHERN Common 3,164
Joseph K. Tannehill SOUTHERN Common 4,541
III-32
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2) - ------------------ -------------- --------------------------
Barbara H. Thames SOUTHERN Common 247
Francis M. Fisher, Jr. SOUTHERN Common 14,873
John E. Hodges, Jr. SOUTHERN Common 48,551
Robert G. Moore SOUTHERN Common 24,517
Arlan E. Scarbrough SOUTHERN Common 26,396
The directors, nominees and executive officers as a group SOUTHERN Common 372,520
MISSISSIPPI
Edwin E. Downer SOUTHERN Common 5,289
Dwight H. Evans SOUTHERN Common 79,309
Robert S. Gaddis SOUTHERN Common 2,143
Linda T. Howard SOUTHERN Common 66
Malcolm Portera SOUTHERN Common 59
George A. Schloegel SOUTHERN Common 589
Philip J. Terrell SOUTHERN Common 945
N. Eugene Warr SOUTHERN Common 1,081
H. E. Blakeslee SOUTHERN Common 36,328
Mark S. Lynch SOUTHERN Common 70
Don E. Mason SOUTHERN Common 45,019
Michael W. Southern SOUTHERN Common 19,730
The directors, nominees and executive officers as a group SOUTHERN Common 190,628
III-33
Name of Directors, Nominees and Number of Shares Executive Officers Title of Class Beneficially Owned (1) (2) - ------------------ -------------- --------------------------
SAVANNAH
Gus H. Bell, III SOUTHERN Common 38
Archie H. Davis SOUTHERN Common 275
Walter D. Gnann SOUTHERN Common 1,757
G. Edison Holland, Jr. SOUTHERN Common 43,065
Robert B. Miller, III SOUTHERN Common 536
Arnold M. Tenenbaum SOUTHERN Common 890
Lewis A. Jeffers SOUTHERN Common 7,923
W. Miles Greer SOUTHERN Common 15,900
Kirby R. Willis SOUTHERN Common 17,992
The directors, nominees and executive officers as a group SOUTHERN Common 88,377
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, 31,701 shares; Mr. Evans, 55,961 shares; Mr. Farris, 38,372 shares; Mr. Franklin, 191,114 shares; Mr. Greer, 12,505 shares; Mr. Harris, 219,394 shares; Mr. Haubein, 37,975 shares; Mr. G. R. Hodges, 38,577 shares; Mr. J. E. Hodges, 24,796 shares; Mr. Holland, 40,342 shares; Mr. Hutchins, 43,701 shares; Mr. Mason, 20,994 shares; Mr. Southern, 15,139 shares, and Mr. Willis, 11,770 shares. Also included are shares of SOUTHERN common stock held by the spouses of the following directors: Mr. Gaddis, 1,200 shares; Mr. Hardman, 100 shares; and Mr. Harris, 310 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, 7,461 shares.
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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 and Chief Executive Officer of AmSouth Bancorporation and AmSouth Bank, Birmingham, Alabama. During 1999, 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 Bank of America Mid-South Banking Group, Atlanta, Georgia; Mr. G. Joseph Prendergast is President and Chief Operating Officer, Wachovia Corporation and Wachovia Bank, N.A., Winston Salem, North Carolina, and Mr. Herman J. Russell is Chairman of the Board of Citizens Trust Bank, Atlanta, Georgia. During 1999, 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 1999, GEORGIA leased a building from Riverside Manufacturing Co. for $86,925. Also, Riverside Manufacturing sold to GEORGIA fire retardant uniforms for $134,464. 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.
In 1999, GULF paid to Merrick Industries, Inc. and Merrick Environmental Technology, Inc., $560,712 for coal handling equipment and air pollution control equipment. Mr. Tannehill is Chairman and Chief Executive Officer of both companies.
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 1999, 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.
III-35
SAVANNAH
Transactions with management and others.
Mr. Archie Davis is President of The Savannah Bank, N.A., Savannah, Georgia; During 1999, this bank furnished a number of regular banking services in the ordinary course of business to SAVANNAH. SAVANNAH intends to maintain normal banking relations with the aforesaid bank in the future.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None. III-36
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form 10-K:
(1) Financial Statements:
Reports of Independent Public Accountants on the financial statements for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed under Item 8