Item 1. BUSINESS
SOUTHERN was incorporated under the laws of Delaware on November 9, 1945. SOUTHERN is domesticated under the laws of Georgia and is qualified to do business as a foreign corporation under the laws of Alabama. SOUTHERN owns all the outstanding common stock of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, each of which is an operating public utility company. ALABAMA and GEORGIA each own 50% of the outstanding common stock of SEGCO. The operating affiliates supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively, and SEGCO owns generating units at a large electric generating station which supplies power to ALABAMA and GEORGIA. More particular information relating to each of the operating affiliates is as follows:
ALABAMA is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company and Houston Power Company. The predecessor Alabama Power Company had had a continuous existence since its incorporation in 1906.
GEORGIA was incorporated under the laws of the State of Georgia on June 26, 1930, and admitted to do business in Alabama on September 15, 1948.
GULF is a corporation which was organized under the laws of the State of Maine on November 2, 1925, and admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976 and in Georgia on November 20, 1984.
MISSISSIPPI was incorporated under the laws of the State of Mississippi on July 12, 1972, was admitted to do business in Alabama on November 28, 1972, and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924, and was admitted to do business in Mississippi on December 23, 1924, and in Alabama on December 7, 1962.
SAVANNAH is a corporation existing under the laws of the State of Georgia; its charter was granted by the Secretary of State on August 5, 1921.
SOUTHERN also owns all the outstanding common stock of Southern Energy, Southern Communications, Southern Nuclear, SCS (the system service company), Energy Solutions and other direct and indirect subsidiaries. Southern Energy is focused on several key international and domestic business lines, including energy distribution, integrated utilities, stand-alone generation, and other energy-related products and services. A further description of Southern Energy's business and organization follows later in this section under "Non-Traditional Business." Southern Communications provides digital wireless communications services to SOUTHERN's operating affiliates and also markets these services to the public within the Southeast. Southern Nuclear provides services to the Southern electric system's nuclear plants. Energy Solutions develops new business opportunities related to energy products and services.
SEGCO owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000 volt transmission lines extending from Plant Gaston to the Georgia state line at which point connection is made with the GEORGIA transmission line system.
The SOUTHERN System
Traditional Business
The transmission facilities of each of the operating affiliates and SEGCO are connected to the respective company's own generating plants and other sources of power and are interconnected with the transmission facilities of the other operating affiliates and SEGCO by means of heavy-duty high voltage lines. (In the case of GEORGIA's integrated transmission system, see Item 1 - BUSINESS - "Territory Served By Operating Affiliates" herein.)
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Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. Additionally, the operating affiliates have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy Corporation, South Carolina Electric & Gas Company and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The operating affiliates have joined with other utilities in the Southeast (including those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the operating affiliates are represented on the National Electric Reliability Council.
An intra-system interchange agreement provides for coordinating operations of the power producing facilities of the operating affiliates and SEGCO and the capacities available to such companies from non-affiliated sources and for the pooling of surplus energy available for interchange. Coordinated operation of the entire interconnected system is conducted through a central power supply coordination office maintained by SCS. The available sources of energy are allocated to the operating affiliates to provide the most economical sources of power consistent with good operation. The resulting benefits and savings are apportioned among the operating affiliates.
SCS has contracted with SOUTHERN, each operating affiliate, Southern Energy, various of the other subsidiaries, Southern Nuclear and SEGCO to furnish, at cost and upon request, the following services: general executive and advisory services, power pool operations, general engineering, design engineering, purchasing, accounting, finance and treasury, taxes, insurance and pensions, corporate, rates, budgeting, public relations, employee relations, systems and procedures and other services with respect to business and operations. Southern Energy, Energy Solutions and Southern Communications have also secured from the operating affiliates certain services which are furnished at cost.
Southern Nuclear has contracted with ALABAMA to operate its Farley Nuclear Plant, as authorized by amendments to the plant operating licenses. Effective March 22, 1997, Southern Nuclear, pursuant to a contract with GEORGIA, assumed responsibility for the operation of plants Hatch and Vogtle, as authorized by amendments to the operating licenses for both plants. See Item 1 BUSINESS - "Regulation - Atomic Energy Act of 1954" herein.
Non-Traditional Business
SOUTHERN continues to consider new business opportunities, particularly those which allow use of the expertise and resources developed through its regulated utility experience. These endeavors began in 1981 and are conducted through Southern Energy and other subsidiaries. SOUTHERN presently has authorization from the SEC (the "SEC Order") which in effect will allow it to use the proceeds from financings for investment in EWGs and FUCOs up to an amount not exceeding 100% of SOUTHERN's consolidated retained earnings. A consumer group that had sought to intervene in the SEC proceeding has filed an appeal, which remains pending, with U.S. Court of Appeals for the 11th Circuit seeking judicial review of the SEC Order. At December 31, 1997, SOUTHERN's consolidated retained earnings amounted to $3,842 million and its aggregate investment in EWGs and FUCOs amounted to $2,795 million.
Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing.
Reference is made to Note 15 to the financial statements of SOUTHERN in Item 8 herein for additional information regarding SOUTHERN's segment and related information.
In 1995, SOUTHERN acquired SWEB, one of the United Kingdom's 12 regional electric distribution companies, for approximately $1.8 billion. In July 1996, a 25 percent interest in SWEB was sold. SWEB is, to some extent, involved in power generation and certain non-regulated activities which include gas marketing and telecommunications. In mid-1997, the acquisition of all interest in CEPA was completed for a total net investment of $2.1 billion. CEPA is engaged in the business of developing, constructing, owning and operating electric power
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generation facilities. Its current operations include installed operating capacity of approximately 3,306 megawatts, with projects either completed or under development in the Philippines, the People's Republic of China, and Pakistan. In September 1997, Southern Energy acquired a 26% interest in a German utility for approximately $820 million. For additional information regarding the acquisitions of SWEB and CEPA, reference is made to Note 14 to SOUTHERN's financial statements in Item 8 herein.
See Item 2
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1997, operated 33 hydroelectric generating stations, 32 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 862,669 (8) Vogtle Augusta, GA 1,060,240 (9) ----------- GEORGIA Total 1,922,909 ---------- Total Nuclear Steam 3,642,909 -----------
Combustion Turbines Greene County Demopolis, AL ALABAMA Total 720,000 ----------- Arkwright Macon, GA 30,580 Atkinson Atlanta, GA 78,720 Bowen Cartersville, GA 39,400 Intercession City Intercession City, FL 47,333 (10) McDonough Atlanta, GA 78,800 McIntosh Units 1,2,3,4,7,8 Effingham County, GA 480,000 McManus Brunswick, GA 481,700 Mitchell Albany, GA 118,200 Robins Warner Robins, GA 160,000 Wilson Augusta, GA 354,100 Wansley Carrollton, GA 26,322 (5) ----------- GEORGIA Total 1,895,155 ---------
Lansing Smith Unit A (GULF) Panama City, FL 39,400
Chevron Cogenerating Station Pascagoula, MS 147,292 (11) Sweatt Meridian, MS 39,400 Watson Gulfport, MS 39,360 --------- MISSISSIPPI Total 226,052 ---------
Boulevard Savannah, GA 59,100 Kraft Port Wentworth, GA 22,000 McIntosh Units 5&6 Effingham County, GA 160,000 SAVANNAH Total 241,100
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------------------------- -------------------- ----------------- Nameplate Generating Station Location Capacity ------------------------- -------------------- ----------------- (Kilowatts)
Gaston (SEGCO) Wilsonville, AL 19,680 (7) Total Combustion Turbines 3,141,387
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 31,145,000
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Notes: (1) For additional information regarding facilities jointly-owned with non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein. (2) Owned by ALABAMA and MISSISSIPPI as tenants in common in the proportions of 60% and 40%, respectively. (3) Excludes the capacity owned by AEC. (4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for GULF is 25% of Unit 3. (5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity. (6) Represents 50% of the plant which is owned as tenants in common by GULF and MISSISSIPPI. (7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS herein.) (8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity. (9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity. (10) Capacity shown represents 33-1/3% of total plant capacity. GEORGIA owns a 1/3 interest in the unit with 100% use of the unit from June through September. FPC operates the unit. (11) Generation is dedicated to a single industrial customer. (12) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity. OPC operates the plant.
Except as discussed below under "Titles to Property," the principal plants and other important units of the operating affiliates and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.
MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a forty-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 1997, the unamortized portion of this cost was $38 million.
The all-time maximum demand on the operating affiliates and SEGCO was 27,419,700 kilowatts and occurred in August 1995. 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. At that time, 29,596,100 kilowatts were supplied by SOUTHERN system generation and 2,176,400 kilowatts (net) were sold to other parties through net purchased and interchanged power. The reserve margin for the operating affiliates and SEGCO at
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that time was 9.4%. For additional information on peak demands, reference is made to Item 6 - SELECTED FINANCIAL DATA herein.
ALABAMA and GEORGIA will incur significant costs in decommissioning their nuclear units at the end of their useful lives. (See Item 1 - BUSINESS "Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and GEORGIA's financial statements in Item 8 herein.)
Other Electric Generation Facilities
Through special purpose subsidiaries, SOUTHERN owns interests in or operates independent power production facilities and foreign utility companies. The generating capacity of these utilities (or facilities) at December 31, 1997, was as follows:
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Jointly-Owned Facilities
ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in certain generating plants and other related facilities to or from non-affiliated parties. The percentages of ownership resulting from these transactions are as follows:
ALABAMA and GEORGIA have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain and Intercession City, as described below) as agent for the joint owners.
In connection with the joint ownership arrangements for Plant Vogtle, GEORGIA made commitments to purchase portions of OPC's and MEAG's capacity and energy from this plant. Declining commitments were in effect during periods of up to seven years following commercial operation and ended in 1996. In addition, the Company has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG's bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the 1987 and 1990 write-offs of Plant Vogtle costs, the cost of such capacity and energy is included in purchased power from non-affiliates in GEORGIA's Statements of Income in Item 8 herein.
In December 1988, GEORGIA and OPC entered into a joint ownership agreement for the Rocky Mountain plant under which GEORGIA agreed to retain its present investment in the project and OPC agreed to finance, complete and operate the facility. In 1995, the plant went into commercial operation. GEORGIA's ownership is 25.4 percent. On January 14, 1998, the GPSC ordered that the Company be allowed approximately $108 million of its $143 million investment in the plant in rate base as of December 31, 1998. GEORGIA has appealed the GPSC's order. If
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such order is ultimately upheld, GEORGIA will be required to record a charge to earnings currently estimated at approximately $29 million, after taxes. 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.
Sale of Property
Reference is made to Note 6 to GEORGIA's financial statements in Item 8 herein for information regarding the sale completed in 1995 of GEORGIA's remaining ownership interest in Plant Scherer Unit 4.
Titles to Property
The operating affiliates' and SEGCO's interests in the principal plants (other than certain pollution control facilities, one small hydroelectric generating station leased by GEORGIA and the land on which five combustion turbine generators of MISSISSIPPI are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the liens of applicable mortgage indentures (except for SEGCO) and to excepted encumbrances as defined therein. The operating affiliates own the fee interests in certain of their principal plants as tenants in common. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) Properties such as electric transmission and distribution lines and steam heating mains are constructed principally on rights-of-way which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In substantially all of its coal reserve lands, SEGCO owns or will own the coal only, with adequate rights for the mining and removal thereof.
Property Additions and Retirements
During the period from January 1, 1993 to December 31, 1997, the operating affiliates, SEGCO, SCS, Southern Nuclear, Southern Communications and Southern Energy recorded gross property additions and retirements as follows:
----------------------- ------------------- --- ---------- Gross Property Additions Retirements --------------- ------------- (in millions) ALABAMA $2,402 $ 415 GEORGIA (1) 2,697 1,534 GULF 336 138 MISSISSIPPI 428 91 SAVANNAH 178 17 SEGCO 29 8 SCS 99 131 Southern Nuclear 6 7 Southern Communications 246 - Southern Energy 1,039 38 Other 6 - ========================================================== SOUTHERN system $7,466 $2,379 ==========================================================
Notes: (1) Includes approximately $446 million attributable to 1993 through 1997 sales of Plant Scherer Unit 4 to FP&L and JEA.
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Item 3.
Item 3. LEGAL PROCEEDINGS
(1) SOUTHERN and Subsidiaries v. Commissioner of the IRS (U.S. Tax Court)
Reference is made to Note 3 to SOUTHERN's, ALABAMA's, and GEORGIA's financial statements in Item 8 herein under the captions "Southern Company Tax Litigation", "Tax Litigation", and "Tax Litigation", respectively.
(2) Frost v. ALABAMA (Circuit Court of Jefferson County, Alabama)
Reference is made to Note 3 to SOUTHERN's and ALABAMA's financial statements in Item 8 herein under the captions "Alabama Power Appliance Warranty Litigation" and "Appliance Warranty Litigation", respectively.
(3) GEORGIA has been designated as a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act with respect to a site in Brunswick, Georgia.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein under the captions "Georgia Power Potentially Responsible Party Status" and "Certain Environmental Contingencies," respectively.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation - - Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's financial statements in Item 8 herein for a description of certain other administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, Southern Energy, SCS, Southern Nuclear, Energy Solutions and Southern Communications 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
ALABAMA, GEORGIA, GULF AND MISSISSIPPI each held special meetings of their shareholders on December 10, 1997, for the purpose of amending their respective charters. The amendments eliminate restrictions on each of these registrant's ability to (1) issue unsecured indebtedness, (2) sell assets, merge or consolidate without preferred shareholder approval under certain circumstances, and (3) pay dividends on common stock.
The vote in connection with such matters was as follows:
FOR ABSTAINED from or AGAINST
ALABAMA 2,373,283 85,507 GEORGIA 2,601,807 52,487 GULF 437,296 5,394 MISSISSIPPI 328,961 16,340
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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, 1997.
A. W. Dahlberg Chairman, President and Chief Executive Officer Age 57 Elected in 1985; President and Chief Executive Officer of GEORGIA from 1988 through 1993. He was elected President of SOUTHERN effective January 1994. He was elected Chairman and Chief Executive Officer effective March 1995.
Paul J. DeNicola Executive Vice President and Director Age 49 Elected in 1989; Executive Vice President of SOUTHERN since 1991. Elected President and Chief Executive Officer of SCS effective January 1994. He previously served as Executive Vice President of SCS from 1991 to 1993.
H. Allen Franklin Executive Vice President and Director Age 53 Elected in 1988; President and Chief Executive Officer of SCS from 1988 through 1993 and, beginning 1991, Executive Vice President of SOUTHERN. He was elected President and Chief Executive Officer of GEORGIA effective January 1994.
Elmer B. Harris Executive Vice President and Director Age 58 Elected in 1989; President and Chief Executive Officer of ALABAMA since 1989 and, beginning 1991, Executive Vice President of SOUTHERN.
David M. Ratcliffe Senior Vice President Age 49 Elected in 1995; President and Chief Executive Officer of MISSISSIPPI from 1991 to 1995. He also serves as Executive Vice President of SCS beginning in 1995. Effective March 1, 1998, elected Executive Vice President and Treasurer of GEORGIA.
W. L. Westbrook Financial Vice President, Chief Financial Officer and Treasurer Age 58 Elected in 1986; responsible primarily for all aspects of financing for SOUTHERN. He has served as Executive Vice President of SCS since 1986.
Thomas G. Boren Vice President Age 48 Elected in 1995; President and Chief Executive Officer of Southern Energy since 1992.
Bill M. Guthrie Vice President Age 64 Elected in 1991; serves as Chief Production Officer for the SOUTHERN system. Senior Executive Vice President of SCS effective January 1994 and Executive Vice President of ALABAMA since 1988. He also serves as Executive Vice President of GEORGIA and Vice President of GULF, MISSISSIPPI and SAVANNAH.
W. G. Hairston, III Age 53 President and Chief Executive Officer of Southern Nuclear since 1993. He previously served as Executive Vice President of GEORGIA from 1989 to March 1997.
Stephen A. Wakefield Senior Vice President and General Counsel Age 57 Elected in 1997. Previously, he was a partner at the firm of Akin, Gump, Strauss, Hauer & Feld, LLP from July 1991 through August 10, 1997.
Each of the above is currently an officer of SOUTHERN, serving a term running from the last annual meeting of the directors (May 28, 1997) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr.Wakefield who was elected on August 11, 1997.
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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 $23-3/8 $20-3/4 Second Quarter 22-1/4 19-7/8 Third Quarter 23 20-13/16 Fourth Quarter 26-1/4 22
First Quarter $25-7/8 $22-3/8 Second Quarter 24-5/8 21-1/4 Third Quarter 24-5/8 21-3/4 Fourth Quarter 23-1/8 21-1/8
------------------ --------------- --- --------------
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 28, 1998, the closing price of SOUTHERN's common stock was $24.6875.
(b) Number of SOUTHERN's common stockholders at December 31, 1997: 200,508
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 1997 1996 ----------------- --------- ------------- ----------
SOUTHERN First $220,194 $211,081 Second 221,544 211,272 Third 222,980 212,200 Fourth 224,287 212,201
ALABAMA First 80,100 76,000 Second 85,600 76,400 Third 86,100 76,400 Fourth 87,800 118,700
GEORGIA First 122,700 121,500 Second 131,000 122,100 Third 131,800 122,100 Fourth 134,500 109,800
GULF First 12,900 12,300 Second 13,800 12,400 Third 13,800 12,400 Fourth 24,100 21,200
MISSISSIPPI First 11,300 10,600 Second 12,100 10,700 Third 12,200 10,600 Fourth 13,800 12,000
SAVANNAH First 5,100 4,800 Second 5,400 4,800 Third 5,500 4,800 Fourth 4,500 5,200 ----------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 31.5(cent) for each quarter of 1996 and 32.5(cent) for each quarter of 1997. The dividend paid on SOUTHERN's common stock for the first quarter of 1998 was raised to 33.5(cent) per share.
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The amount of dividends on their common stock that may be paid by the subsidiary registrants is restricted in accordance with their first mortgage bond indenture and, in the case of SAVANNAH, its charter. The amounts of earnings retained in the business and the amounts restricted against the payment of cash dividends on common stock at December 31, 1997, were as follows:
------------------ ------------------ --- -------------- Retained Restricted Earnings Amount ------------------ -------------- (in millions) ALABAMA $1,221 $ 796 GEORGIA 1,745 897 GULF 172 127 MISSISSIPPI 170 118 SAVANNAH 113 68 Consolidated 3,842 2,024 ------------------ ------------------ --- --------------
Item 6.
Item 6. SELECTED FINANCIAL DATA
SOUTHERN. Reference is made to information under the heading "Selected Consolidated Financial and Operating Data," contained herein at pages II-41 through II-54.
ALABAMA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-83 through II-96.
GEORGIA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-129 through II-143.
GULF. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-172 through II-185.
MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-212 through II-225.
SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-247 through II-259.
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-16.
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-58 through II-64.
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-100 through II-107.
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-147 through II-154.
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-189 through II-195.
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-229 through II-234.
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" and "Financial Instruments for Trading" contained herein on pages II-13 through II-14; and pages II-26 through II-28, respectively.
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II-4
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
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MANAGEMENT'S REPORT Southern Company and Subsidiary Companies 1997 Annual Report
The management of Southern Company has prepared -- and is responsible for -- the consolidated financial statements and related information included in this report. These statements were prepared in accordance with generally accepted accounting principles appropriate in the circumstances and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that books and records reflect only authorized transactions of the company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The company's system of internal accounting controls is evaluated on an ongoing basis by the company's internal audit staff. The company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of five directors who are not employees, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the company's operations are conducted according to a high standard of business ethics.
In management's opinion, the consolidated financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Southern Company and its subsidiary companies in conformity with generally accepted accounting principles.
/s/A. W. Dahlberg A. W. Dahlberg Chairman, President, and Chief Executive Officer
/s/W. L. Westbrook W. L. Westbrook Financial Vice President, Chief Financial Officer, and Treasurer
February 11, 1998
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and to the Stockholders of 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, 1997 and 1996, and the related consolidated statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements (pages 11-17 through 11-40) referred to above present fairly, in all material respects, the financial position of Southern Company and subsidiary companies as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
/s/Arthur Andersen LLP Atlanta, Georgia February 11, 1998
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 1997 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
Southern Company reported 1997 earnings of $972 million or $1.42 for both basic and diluted earnings per share. The traditional core business of selling electricity in the southeastern United States remained strong, while non-traditional business results were adversely affected by a $111 million, after taxes, windfall profits tax assessed against South Western Electricity (SWEB) in the United Kingdom. SWEB is a subsidiary of Southern Energy, Inc. (Southern Energy). Excluding the windfall profits tax, Southern Energy's earnings account for 10 percent of consolidated net income in 1997. Consolidated net income decreased by $155 million compared with the amount reported for 1996. Continued cost controls and steady demand for electricity were offset by increased financing costs for the non-traditional business and the windfall profits tax.
Costs related to work force reduction programs decreased earnings by $31 million or 5 cents per share and $53 million or 8 cents per share in 1997 and 1996, respectively. These costs are expected to be recovered through future savings in approximately two years following each program's implementation.
In 1996, earnings were $1.1 billion or $1.68 for both basic and diluted earnings per share -- up 2 cents from the per share amount reported in 1995. Earnings in 1996, when compared with 1995 results, were affected by increased energy sales and growth in the non-traditional business.
Dividends paid on common stock during 1997 were $1.30 per share or 321/2 cents per quarter. During 1996 and 1995, dividends paid per share were $1.26 and $1.22, respectively. In January 1998, the Southern Company raised the quarterly dividend to 331/2 cents per share or an annual rate of $1.34 per share.
Acquisitions
Southern Energy owns and manages international and domestic non-traditional electric power production and delivery facilities for Southern Company. Southern Energy's acquisitions of 100 percent of Consolidated Electric Power Asia (CEPA) and a 26 percent interest in a German utility were completed in 1997. Also, Southern Energy acquired SWEB in late 1995. These businesses have been included in the consolidated financial statements since the dates of acquisition and are not reflected in prior periods. As a result, changes in revenues and expenses for Southern Energy in 1997 and 1996 reflect significant amounts related to acquisitions, which were not fully reflected in each year being compared. Therefore, to facilitate discussing the results of operations for business segments, Southern Energy's variances are primarily driven by the above reason unless otherwise noted.
Revenues
Operating revenues increased in 1997 and 1996 as a result of the following factors:
Increase (Decrease) From Prior Year --------------------------------- 1997 1996 1995 --------------------------------- Retail -- (in millions) Growth and price change $ 105 $ 124 $ 177 Weather (110) (64) 143 Fuel cost recovery and other (13) 2 134 --------------------------------------------------------------- Total retail (18) 62 454 --------------------------------------------------------------- Sales for resale -- Within service area (28) 10 39 Outside service area 76 14 (90) --------------------------------------------------------------- Total sales for resale 48 24 (51) Southern Energy 2,154 1,040 458 Other operating revenues 69 52 22 --------------------------------------------------------------- Total operating revenues $2,253 $1,178 $ 883 =============================================================== Percent change 21.8% 12.8% 10.6% ---------------------------------------------------------------
Retail revenues of $7.6 billion declined slightly compared with last year. Continued growth in the traditional service area was offset by the negative impact of weather on energy sales and by industrial and commercial customers taking advantage of lower load management rates. This trend will probably continue as the utility industry becomes much more competitive. In 1996, retail revenues barely increased by 0.8 percent compared with the year 1995. Under fuel cost recovery provisions, fuel revenues generally equal fuel expense -- including the fuel component of purchased energy -- and do not affect net income.
Sales for resale revenues within the service area were $381 million in 1997, down 7.1 percent from the prior year. This decrease resulted primarily from supplying less electricity under contractual agreements with certain wholesale customers in 1997. Revenues from sales for resale within the service area were
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
$409 million in 1996, up 2.5 percent from the prior year.
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components were as follows:
1997 1996 1995 ------------------------------------ (in millions) Capacity $203 $217 $237 Energy 183 176 151 --------------------------------------------------------- Total $386 $393 $388 =========================================================
Capacity revenues decreased in 1997 and 1996 because the amount of capacity under contract declined slightly during 1996. Additional declines in capacity are not scheduled until after 1999.
Southern Energy's revenues have escalated to $3.8 billion and $1.7 billion in 1997 and 1996, respectively. These rapid increases are primarily attributable to the development and growth of energy trading and marketing activities, primarily in 1997. Also, revenues have increased as a result of international acquisitions. In 1997, energy trading and marketing revenues increased $1.9 billion compared with amounts recorded in 1996. However, these revenues were substantially offset by purchased power expenses incurred in completing these trading and marketing transactions. Energy trading and marketing -- similar to other low margin sales activities -- is dependent on huge volumes for profitability.
Changes in traditional core business revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1997 and the percent change by year were as follows:
(billions of kilowatt-hours) Amount Percent Change ---------- ---------------------------- 1997 1997 1996 1995 ---------- ----------------------------
Residential 39.2 (2.2)% 2.5% 9.2% Commercial 38.9 2.5 5.7 5.5 Industrial 54.2 2.6 2.2 2.7 Other 0.9 (1.1) 5.7 2.1 ---------- Total retail 133.2 1.1 3.3 5.4 Sales for resale -- Within service area 9.9 (9.6) 15.4 16.2 Outside service area 13.3 23.6 17.9 (15.1) ---------- Total 156.4 1.9 5.0 4.4 ===================================================================
The rate of increase in 1997 retail energy sales was significantly lower than the past two years. Although the total number of residential customers served increased by 63,000 during the year, residential energy sales experienced a decline as a result of milder weather in 1997, compared with closer to normal weather in 1996. Commercial and industrial sales both in 1997 and 1996 continued to show slight gains in excess of the national averages. This reflects the strength of business and economic conditions in Southern Company's traditional service area. Energy sales to retail customers are projected to increase at an average annual rate of 2.1 percent during the period 1998 through 2008.
Energy sales for resale outside the service area are predominantly unit power sales under long-term contracts to Florida utilities. Economy sales and amounts sold under short-term contracts are also sold for resale outside the service area. Sales to customers outside the service area increased in both 1997 and 1996 and declined in 1995 when compared with the respective prior year. However, these fluctuations in energy sales under long-term contracts have minimal effect on earnings because Southern Company is paid for dedicating specific amounts of its generating capacity to these utilities outside the service area.
Expenses
Total operating expenses of $10.7 billion for 1997 increased $2.2 billion compared with the prior year. Traditional core business expenses increased $69 million. Southern Energy's expenses increased almost $2.1 billion. The sharp increase for Southern Energy resulted primarily from two factors. First, the acquisition of CEPA is reflected only in 1997 expenses. Second, nearly $1.9 billion relates to energy trading and marketing activities, which is included in purchased power expenses. The costs to produce and deliver electricity for the traditional core business in 1997 increased by $37 million to meet higher energy demands. Also, costs related to work force reduction programs decreased in 1997 by $35 million. Traditional core business depreciation expenses and taxes other than income taxes increased by $158 million as a result of additional utility plant being placed into service and increased accelerated depreciation of certain assets.
In 1996, operating expenses of $8.5 billion increased 16.6 percent compared with 1995. Traditional core business expenses increased $173 million. Southern Energy's expenses increased $976 million. The large increase for Southern Energy resulted primarily from SWEB, which was acquired in late 1995. The costs to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
produce and deliver electricity for the traditional core business in 1996 increased by $79 million to meet higher energy demands. Also, costs related to work force reduction programs increased expenses by $58 million compared with such expenses in 1995. Depreciation expense and taxes other than income taxes increased $39 million.
Fuel costs constitute the single largest expense for Southern Company's traditional core business. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated -- within the core business service area -- were as follows:
1997 1996 1995 -------------------------- Total generation (billions of kilowatt-hours) 160 156 147 Sources of generation (percent) -- Coal 77 77 77 Nuclear 17 17 17 Hydro 4 4 4 Oil and gas 2 2 2 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.63 1.65 1.73 Nuclear 0.53 0.52 0.56 Total 1.46 1.48 1.53 - --------------------------------------------------------------
Total fuel and purchased power expenses of $5.3 billion in 1997 increased $2.0 billion compared with the prior year. These expenses for traditional core business increased $32 million and, Southern Energy's portion increased $1.9 billion. The traditional core business's customer demand for electricity rose by 1.6 billion kilowatt-hours more than in 1996. The additional cost to meet the demand was offset slightly by a lower average cost of fuel per net kilowatt-hour generated. Southern Energy's increase in expenses escalated as a result of energy trading and marketing activities discussed earlier. Fuel and purchased power costs of $3.3 billion in 1996 increased $731 million compared with 1995. Traditional core business increased $49 million and Southern Energy increased $682 million because of the acquisition of SWEB in late 1995.
Excluding the windfall profits tax in the United Kingdom, total income taxes in 1997 declined by $66 million compared with the amount in 1996. Southern Energy's portion was a reduction of $37 million. For 1996, traditional core business income taxes decreased $40 million, and Southern Energy increased $41 million.
Total net interest charges and capital and preferred stock expenses increased $248 million from amounts reported in the previous year. These costs for traditional core business overall netted out to be nearly flat compared with the reported amounts in 1996. Southern Energy's costs increased $221 million related primarily to financing acquisitions. In 1996, these same costs for traditional core business declined by $69 million, but Southern Energy's interest charges increased $85 million. The decline in costs for core business was attributable to lower interest rates and continued refinancing activities in 1996. As a result of favorable market conditions, $1.7 billion in 1997, $574 million in 1996, and $1.1 billion in 1995 of traditional senior securities were issued for the primary purpose of retiring higher-cost securities.
Effects of Inflation
Southern Company's traditional core business is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on Southern Company because of the large investment in long-lived utility plant. 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 stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company's future earnings depends on numerous factors. Two major factors are: achieving energy sales growth in a less regulated, more competitive environment; and operating non-traditional business activities successfully.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Southern Company continues to position its business to meet the challenges of a new competitive environment. Work force reduction programs have reduced earnings by $31 million, $53 million, and $17 million for the years 1997, 1996, and 1995, respectively. These actions -- in conjunction with other cost containment programs -- will assist efforts to continue being a low-cost provider of electricity.
The operating companies currently operate as vertically integrated companies providing electricity to customers within the traditional service area of the southeastern United States. Prices for electricity provided by the operating companies to retail customers are set by state public service commissions under cost-based regulatory principles.
Rates for Alabama Power and Mississippi Power are adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return. Georgia Power is required to file a general rate case by July 1, 1998. See Note 3 to the financial statements for information about other retail and wholesale regulatory matters.
Future earnings for the operating companies in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the company's service area.
The electric utility industry in the United States is currently undergoing a period of dramatic change as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Southern Company is aggressively working to maintain and expand its share of wholesale sales in the Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. As these initiatives materialize, the structure of the utility industry could radically change. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been or are being discussed in Alabama, Florida, Georgia, and Mississippi, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. The inability of an operating company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on the financial condition of that operating company. The operating companies are attempting to minimize or reduce their cost exposure. See Note 3 to the financial statements for information regarding these efforts.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, unless Southern Company remains a low-cost producer and provides quality service, the company's retail energy sales growth could be limited, and this could significantly erode earnings.
To adapt to a less regulated, more competitive environment, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, acquisitions involving other utility or non-utility businesses or properties, internal restructuring, disposition of certain assets, or some combination thereof. Furthermore, Southern Company may engage in other new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations and financial condition of Southern Company.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA). The amendment allows 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
evolving opportunities, Southern Energy -- founded in 1981 -- is focused on several key international and domestic business lines, including energy distribution, integrated utilities, stand-alone generation, and other energy-related products and services. As the energy marketplace evolves, Southern Energy is positioning the company to become a major competitor in energy trading and marketing activities. As part of this strategy, Southern Energy entered into a joint venture with Vastar Resources effective in January 1998. The two companies combined their energy trading and marketing operations to form a new full-service energy provider, Southern Company Energy Marketing. Also, Southern Energy is expanding its international business through acquisitions. In September 1997, Southern Energy acquired a 26 percent interest in a German utility for approximately $820 million. Also, the acquisition of CEPA for a total net investment of some $2.1 billion was completed in mid-1997. In late 1995, SWEB was acquired for approximately $1.8 billion. In July 1996, a 25 percent interest in SWEB was sold. For additional information on acquisitions, see Note 14 to the financial statements.
The CEPA acquisition has a slightly dilutive impact on earnings in the near term. However, Southern Energy's investments should strengthen the opportunities for Southern Company's long-term future earnings growth. At December 31, 1997, Southern Energy's total assets amounted to $11 billion.
The depreciation of southeast Asian currencies is likely to increase the cost of electricity that nationally owned utilities purchase from independent power projects relative to the prices received by those utilities from their customers. This could cause a deterioration in the financial condition of nationally owned utilities, which could potentially impact these utilities' ability to meet their obligations under existing contracts and could reduce the near-term opportunities for greenfield independent power projects in the region. However, fewer greenfield opportunities may, to some extent, be offset by increased opportunities for CEPA to acquire projects from regional developers who have been adversely affected by the financial crisis, and also by a possible increase in the pace of privatizations by regional governments needing to raise capital.
Also during 1997, there was a substantial depreciation of the Philippine peso relative to the U.S. dollar. However, the long-term power sales contracts that govern CEPA's revenues from existing projects in the Philippines provide for U.S. dollar payments, or indexing to the U.S. dollar. This should sufficiently cover foreign currency costs of operation, including debt service and return on and of capital. The National Power Corporation, whose obligations are guaranteed by the Republic of the Philippines, is the counterparty to these contracts.
The staff of the Securities and Exchange Commission (SEC) has questioned certain of the current accounting practices of the electric utility industry -- including Southern 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 Financial Accounting Standards Board (FASB) has decided to review the accounting for liabilities related to closure and removal of long-lived assets, including nuclear decommissioning. If the FASB issues new accounting rules, the estimated costs of closing and removing 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 closure and removal 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.
Southern Company is heavily dependent upon complex computer systems for all phases of its operations. The year 2000 issue --common to most corporations -- concerns the inability of certain software and databases to properly recognize date-sensitive information related to the year 2000 and thereafter. This problem could result in a material disruption to the company's operations, if not corrected. Southern Company has assessed and developed a detailed strategy to prevent or at least minimize problems related to the year 2000 issue. In 1997, resources were committed and implementation began to modify the affected information systems. Total costs related to the project are estimated to be approximately $85 million, of which $8 million was spent in 1997. Most all remaining costs will be expensed in 1998. Implementation is currently on schedule. Although the degree of success of this project cannot be determined at this time, management believes there will be no significant effect on the company's operations.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
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 operating companies are subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of a company's operations is no longer subject to these provisions, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standard
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which will be effective in 1998. This statement establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. The objective of the statement is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners (comprehensive income). Comprehensive income is the total of net income and all other non-owner changes in equity. Southern Company will adopt this statement in 1998.
FINANCIAL CONDITION
Overview
Southern Company's financial condition continues to remain strong. The company's common stock closed 1997 with the highest year-end closing price in history. Earnings, excluding the windfall profits tax, were some $1.1 billion. Based on this performance, in January 1998, the Southern Company board of directors increased the common stock dividend for the seventh consecutive year.
Gross property additions to utility plant were $1.9 billion in 1997. The majority of funds needed for gross property additions since 1994 has been provided from operating activities, principally from earnings and non-cash charges to income. Southern Energy's business acquisitions in 1997 amounted to approximately $2.9 billion. The Consolidated Statements of Cash Flows provide additional details.
Derivative Financial Instruments
Southern Company is exposed to market risks in both its trading and non-trading operations. The non-trading operations are exposed to market risks, including changes in interest rates, currency exchange rates, and certain commodity prices. To mitigate changes in cash flows attributable to these exposures, the company has entered into various derivative financial instruments. Company policy for non-trading activities stipulates that derivatives are to be used only for hedging purposes. Derivative positions are monitored using techniques that include market value and sensitivity analysis.
Interest rate swaps are used to hedge underlying debt obligations. These swaps hedge specific debt issuances and therefore qualify for hedge accounting. The company has interest rate swaps in various currencies. These match debt issued in the same currency. In cases where debt is issued in currencies other than the functional currency, currency swaps convert the exposure to that of the functional currency. For qualifying hedges, the interest rate differential is reflected as an adjustment to interest expense over the life of the instruments.
If the company sustained a 100 basis point change in interest rates for all variable rate debt in all currencies, the change would affect annualized interest expense by approximately $35 million at December 31, 1997. Based on the company's overall interest rate exposure at December 31, 1997, 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 various emerging market countries where the net investments are not hedged, including Argentina, Chile, Trinidad, Bahamas, Philippines, and China. The company relies on either currency pegs or contractual or regulatory links to the U.S. dollar to mitigate currency risk attributable to these investments. The company does not believe it has a material exposure to changes in exchange rates between the U.S. dollar and the currencies of these countries. The company also has investments in the United Kingdom and Germany, and for these investments the company uses long-term cross-currency agreements to reduce a substantial portion of its exposure to fluctuations in the British pound sterling and German Deutschemark. These instruments are used to hedge its net investments in these countries. As a
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
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 uses currency swaps and forward agreements to hedge dollar denominated debt issued by subsidiaries with different functional currency. These swaps offset the dollar flows, thereby effectively converting debt to the appropriate currency. Gains and losses related to qualified hedges of foreign currency firm commitments are deferred and included in the basis of the underlying transactions.
In addition to the non-trading activities, the company is exposed to market risks through its electricity and natural gas commodity trading business. To estimate and manage the market risk of its trading and marketing portfolio, Southern Energy employs a daily Value at Risk (VAR) methodology. VAR is used to describe a probabilistic approach to measuring the exposure to market risk. VAR models are relatively sophisticated. However, the quantitative risk information is limited by the parameters established in creating the model. The instruments being evaluated may have features that may trigger a potential loss in excess of calculated amounts if the changes in commodity prices exceed the confidence level of the model used. The calculation utilizes the standard deviation of seasonally adjusted historical changes in the value of the market risk sensitive commodity-based financial instruments to estimate the amount of change (i.e., volatility) in the current value of these instruments that could occur at a specified confidence level over a specified holding interval. The parameters used in the calculation include holding intervals ranging from five to 20 days, depending upon the type of instrument, the term of the instrument, the liquidity of the underlying market, and other factors. The models employed a 95 percent confidence level based on historical price movement. Based on the company's VAR analysis of its overall commodity price risk exposure at December 31, 1997, management does not anticipate a materially adverse effect on the company's consolidated financial statements as a result of market fluctuations.
In the United Kingdom, the company utilizes contracts to mitigate its exposure to volatility in the prices of electricity purchased through the wholesale electricity market. These contracts are in place to hedge electricity purchases on approximately 20 billion kilowatt-hours through the year 2008. The gains or losses realized on such contracts are deferred and recognized as electricity is purchased. Because of the absence of a trading market, it is not practicable to estimate the fair value of these contracts.
Due to cost-based rate regulations, the operating companies have limited exposure to market volatility in interest rates and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the operating companies enter into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1997, 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."
Capital Structure
Southern Company achieved a ratio of common equity to total capitalization -- including short-term debt -- of 38.6 percent in 1997, compared with 45.1 percent in 1996, and 42.4 percent in 1995.
During 1997, the subsidiary companies sold, through public authorities, $404 million of pollution control revenue bonds. Preferred securities of $1.3 billion were issued in 1997. The companies continued to reduce financing costs by retiring higher-cost bonds and preferred stock. Retirements, including maturities, of bonds totaled $507 million during 1997, $600 million during 1996, and $1.3 billion during 1995. As a result, the composite interest rate on long-term debt decreased from 7.2 percent at December 31, 1994 to 6.6 percent at December 31, 1997. Retirements of preferred stock totaled $660 million during 1997, $179 million during 1996, and $1 million during 1995.
In 1997, Southern Company raised $360 million from the issuance of new common stock under the company's various stock plans. At the close of 1997, the company's common stock had a market value of 257/8 per share, compared with a book value of $13.91 per share. The market-to-book value ratio was 186 percent at the end of 1997, compared with 166 percent at year-end 1996, and 188 percent at year-end 1995.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $2.0 billion for 1998, $2.0 billion for 1999, and $1.6 billion for 2000. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
The operating companies have approximately 1,600 megawatts of combined cycle generation scheduled to be placed in service by 2001. Southern Energy has under construction some 1,400 megawatts of owned capacity. Significant construction of transmission and distribution facilities and upgrading of generating plants will be continuing for the core business in the Southeast.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.5 billion will be required by the end of 2000 for present sinking 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
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants are required in two phases. Phase I compliance began in 1995 and initially affected 28 generating units of Southern Company. As a result of the company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Phase I compliance totaled approximately $300 million.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as necessary to meet Phase II limits and ozone non-attainment requirements for metropolitan Atlanta through 2000. Current compliance strategy for Phase II and ozone non-attainment could require total estimated construction expenditures of approximately $70 million, of which $55 million remains to be spent.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. Also, in October 1997, the EPA issued a proposed regional ozone rule -- if implemented -- that could make substantial further reductions in NOx emissions from fossil-fueled generating facilities. Implementation of the standards and the proposed rule could result in significant additional compliance costs and capital expenditures that cannot be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; and hazardous waste disposal requirements. The impact of new standards will depend on the development and implementation of applicable regulations.
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 1997 and $8 million in 1995. In 1996, the company was reimbursed $6 million for amounts previously expensed. Additional sites may
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1997 Annual Report
require environmental remediation for which the subsidiaries may be liable for a portion or all required cleanup costs. See Note 3 to the financial statements for information regarding Georgia Power's potentially responsible party status at a site in Brunswick, Georgia.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of Southern Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect Southern Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The amount and timing of additional equity capital to be raised in 1998 -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. Equity capital can be provided from any combination of public offerings, private placements, or the company's stock plans. Any portion of the common stock required during 1998 for the company's stock plans that is not provided from the issuance of new stock will be acquired on the open market in accordance with the terms of such plans.
The operating companies plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from internal sources. However, the type and timing of any financings - -- if needed -- will depend on market conditions and regulatory approval.
The operating companies historically have relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control revenue bonds issued for their benefit by public authorities, to meet their long-term external financing requirements. Recently, the operating companies' financings have consisted of unsecured debt and trust preferred securities. In this regard, the operating companies -- except Savannah Electric -- sought and obtained stockholder approval in 1997 to amend their respective corporate charters eliminating restrictions on the amounts of unsecured indebtedness they may incur.
To meet short-term cash needs and contingencies, Southern Company had approximately $601 million of cash and cash equivalents and $4.9 billion of unused credit arrangements with banks at the beginning of 1998.
Cautionary Statement Regarding Forward-Looking Information
Southern Company's 1997 Annual Report contains forward-looking statements in addition to 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 statements; 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 the non-traditional business and the success of efforts to invest in and develop new opportunities; and other factors discussed in the reports -- including Form 10-K -- filed from time to time by the company with the SEC.
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NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Company Energy Solutions, Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), and other direct and indirect subsidiaries. The operating companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four southeastern states. Contracts among the operating companies -- dealing with jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern Communications provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The operating companies also are subject to regulation by the FERC and their respective state regulatory commissions. The companies follow generally accepted accounting principles and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates, and the actual results may differ from those estimates. All material intercompany items have been eliminated in consolidation.
The consolidated financial statements reflect investments in controlled subsidiaries on a consolidated basis and other investments on an equity basis. Effective in January 1998, Southern Energy and Vastar Resources combined their energy trading and marketing activities to form a joint venture. Southern Energy's investment in the joint venture will be accounted for under the equity method of accounting. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform with the current year presentation.
Regulatory Assets and Liabilities
The operating companies are subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the operating companies associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Consolidated Balance Sheets at December 31 relate to the following:
1997 1996 ------------------------ (in millions) Deferred income taxes $1,142 $1,238 Deferred Plant Vogtle costs 50 171 Premium on reacquired debt 285 289 Demand-side programs 11 44 Department of Energy assessments 63 69 Vacation pay 79 77 Deferred fuel charges 4 29 Postretirement benefits 38 38 Work force reduction costs 37 48 Deferred income tax credits (746) (814) Storm damage reserves (36) (32) Other, net 152 114 - ----------------------------------------------------------------- Total $1,079 $1,271 =================================================================
In the event that a portion of an operating company's operations is no longer subject to the provisions of FASB Statement No. 71, the company would be required to write off related net regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Revenues and Fuel Costs
The operating companies accrue revenues for service rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The operating companies' electric rates include provisions to adjust billings for fluctuations in fuel, 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.
Southern Energy's revenues for product sales and marketing services are recognized when title passes to the customer or when service is performed.
The operating companies have a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1997, 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 $144 million in 1997, $142 million in 1996, and $140 million in 1995. Alabama Power and Georgia Power have contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of spent nuclear fuel. Although disposal was scheduled to begin in 1998, the actual year this service will begin is uncertain. Sufficient storage capacity currently is available to permit operation into 2003 at Plant Hatch, into 2008 at Plant Vogtle, and into 2010 and 2013 at Plant Farley units 1 and 2, respectively. Activities for adding dry cask storage capacity at Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. Alabama Power and Georgia Power -- based on its ownership interests -- estimate their respective remaining liability at December 31, 1997, under this law to be approximately $34 million and $27 million, respectively. These obligations are recorded in the Consolidated Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.4 percent in 1997 and 3.3 percent in 1996 and 1995. 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 $159 million in 1997, $24 million in 1996, and $6 million in 1995. See Note 3 under "Georgia Power Retail Accounting Order" for additional information.
The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. Alabama Power and Georgia Power have external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the respective state public service commissions. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission a specific facility as of the site study year, and ultimate cost is the estimate to decommission a
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
specific facility as of retirement date. The estimated costs of decommissioning - -- both site study costs and ultimate costs -- at December 31, 1997, 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) 1993 1997 1997
Decommissioning periods: Beginning year 2017 2014 2027 Completion year 2029 2027 2038 - ----------------------------------------------------------------- (in millions) Site study costs: Radiated structures $489 $372 $317 Non-radiated structures 89 33 44 - ----------------------------------------------------------------- Total $578 $405 $361 =================================================================
Ultimate costs: Radiated structures $1,504 $722 $922 Non-radiated structures 274 65 129 - ----------------------------------------------------------------- Total $1,778 $787 $1,051 =================================================================
Plant Plant Plant Farley Hatch Vogtle ----------------------------- (in millions)
Amount expensed in 1997 $ 18 $ 11 $ 9
Accumulated provisions: Balance in external trust funds $193 $118 $76 Balance in internal reserves 44 23 13 - ------------------------------------------------------------------ Total $237 $141 $89 ==================================================================
Significant assumptions: Inflation rate 4.5% 3.6% 3.6% Trust earning rate 7.0 6.5 6.5 - ------------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the respective state public service commissions. All of Alabama Power's decommissioning costs are approved for ratemaking. For Georgia Power, only the costs to decommission the radioactive portion of the plants are currently included in cost of service. Georgia Power's decommissioning costs currently included in cost of service are $320 million and $267 million for plants Hatch and Vogtle, respectively. The estimated ultimate costs associated with the amounts currently included in cost of service are $781 million and $1.1 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.
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.
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.
Plant Vogtle Phase-In Plans
In 1987, 1989, and 1991, the Georgia Public Service Commission (GPSC) ordered that the allowed costs of Plant Vogtle, a two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased into rates. Each GPSC order called for recovery of deferred costs within 10 years. Under these plans, all allowed costs will be recovered by 1999.
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 operating companies to calculate AFUDC during the years 1995 through 1997 ranged from a before-income-tax rate of 5.8 percent to 9.8 percent. AFUDC, net of income tax, as a percent of consolidated net income was 1.6 percent in 1997, 1.4 percent in 1996, and 1.6 percent in 1995.
Utility Plant
Utility plant is stated at original cost less regulatory disallowances. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property -- exclusive of minor items of property -- is charged to utility plant.
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Leasehold Interests
Leasehold interests include Southern Energy's power generation facilities that are developed under build, operate, and transfer agreements with foreign governments. Southern Energy's construction costs are initially recorded as construction work in progress, and -- after completion -- these costs are recorded as leasehold interests. These costs are amortized over the length of time the facility is operated before transferring ownership to the local government.
Cash and Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Foreign Currency Translation
Assets and liabilities of Southern Company's international operations, where the local currency is the functional currency, have been translated at year-end exchange rates, and revenues and expenses have been translated using average exchange rates prevailing during the year. Adjustments resulting from translation have been recorded in stockholders' equity. The financial statements of international operations, where the U.S. dollar is the functional currency and when certain transactions are denominated in a local currency, are remeasured in U.S. dollars. The remeasurement of local currencies into U.S. dollars creates adjustments. These adjustments and all gains and losses from foreign currency transactions are included in consolidated net income. Foreign exchange gains and losses are not material for all periods presented.
Financial Instruments for Non-Trading
Non-trading derivative financial instruments are used to hedge exposures to fluctuations in interest rates, foreign currency exchange rates, and certain commodity prices. Gains and losses on qualifying hedges are deferred and recognized either in income or as an adjustment to the carrying amount when the hedged transaction occurs.
The company utilizes interest rate swaps and cross currency interest rate swaps to minimize borrowing costs by changing the interest rate and currency of the original borrowing. For qualifying hedges, the interest rate differential is reflected as an adjustment to interest expense over the life of the swaps.
Southern Company's international operations are exposed to the effects of foreign exchange rate fluctuations. To protect against this exposure, the company utilizes currency swaps to hedge its net investment in certain foreign subsidiaries, which has the effect of converting foreign currency cash inflows into U.S. dollars at fixed exchange rates. Gains or losses on these currency swaps, designated as hedges of net investment, are offset against the translation effects reflected in stockholders' equity, net of tax.
Non-trading financial derivative instruments held at December 31, 1997, were as follows:
Year of Unrecognized Maturity or Notional Gain Type Termination Amount (Loss) - ------------------------------------ --------------------------- (in millions) Interest rate swaps: 2002-2012 $710 $(33) 2001-2012 (pound)500 $(52) 2002-2007 DM691 $(3) Cross currency swaps 2001-2007 (pound)439 $6 Cross currency swaption 2003 DM570 $1 - --------------------------------------------------------------- (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 does not expect any of the counterparties to fail to meet their obligations.
In the United Kingdom, the company utilizes contracts to mitigate its exposure to volatility in the prices of electricity purchased through the wholesale electricity market. These contracts are in place to hedge electricity purchases of approximately 20 billion kilowatt-hours through the year 2008. The gains or losses realized on such contracts are deferred and recognized as electricity is purchased. Because of the absence of a trading market, it is not practicable to estimate the fair value of these contracts .
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Other Southern Company financial instruments for which the carrying amount did not equal fair value at December 31 were as follows:
Carrying Fair Amount Value -------------------------- (in millions) Long-term debt: At December 31, 1997 $10,916 $11,160 At December 31, 1996 7,975 8,122 Capital and preferred securities: At December 31, 1997 1,744 1,826 At December 31, 1996 422 427 - -----------------------------------------------------------------
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
Derivative financial instruments used for trading purposes primarily relate to commodities associated with the energy sector, such as electricity, natural gas, and crude oil. These instruments are recorded at fair value for balance sheet purposes. The determination of fair value considers various factors, such as closing exchange prices, broker price quotations, and model pricing. Model pricing considers time value and volatility factors underlying any options and contractual commitments. These transactions are accounted for using the mark-to-market method of accounting in which the unrealized gains or losses resulting from the impact of price movements are recognized as net gains or losses in the consolidated statements of income. If the company has a master netting agreement with counterparties, net positions are recognized for consolidated balance sheet and income statement purposes.
The company provides price risk management services by entering into a variety of contractual commitments such as price cap and floor agreements, futures contracts, forward purchase and sale agreements, and option contracts. These contracts generally require future settlement, and are either executed on an exchange or traded as over-the-counter (OTC) instruments. Contractual commitments have widely varying terms and durations that range from a few hours to a number of years depending on the instrument. The majority of the company's transactions are short-term in duration, with a weighted average maturity of approximately 1.3 years and 0.6 years at December 31, 1997 and 1996, respectively.
All contractual commitments used for trading purposes are recorded at fair value. Contracts in a net receivable position, as well as options held, are reported as assets. Similarly, contractual commitments in a net payable position, as well as options written, are reported as liabilities. The net unrealized gain from risk management services amounted to $8 million at December 31, 1997. Southern Company has made guarantees to certain counterparties regarding performance of contractual commitments by its affiliates related to trading and marketing activities. Contractual commitments reflected in the Consolidated Balance Sheets at December 31 were as follows:
Net Fair Value Notional ------------------------- Amounts 1997 (Kilowatt-Hours) Assets Liabilities - ---------- --------------------------------------------- (in millions) Exchange-issued products: Futures contracts 904 $14 $15 Other 958 1 1 - ------------------------------------------------------------------- Total 1,862 15 16 - ------------------------------------------------------------------- OTC products: Forward contracts 2,643 69 62 Swaps (473) 1 - Other 639 9 8 - ------------------------------------------------------------------- Total 2,809 79 70 - ------------------------------------------------------------------- Total 4,671 $94 $86 ===================================================================
Net Fair Value Notional ----------------------- Amounts 1996 (Kilowatt-Hours) Assets Liabilities - ------------ --------------------------------------------- (in millions) Exchange-issued products: Futures contracts 42 $ 3 $ 3 Other 105 - - - ------------------------------------------------------------------- Total 147 3 3 - ------------------------------------------------------------------- OTC products: Forward contracts 56 15 15 Swaps - - - Other 51 - - - ------------------------------------------------------------------- Total 107 15 15 - ------------------------------------------------------------------- Total 254 $18 $18 ===================================================================
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Notional amounts -- stated in equivalent millions of kilowatt-hours -- are indicative only of the volume of activity and are not a measure of market risk. Notional amounts of natural gas and crude oil positions are reflected in equivalent kilowatt-hours based on standard conversion rates. 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. A concentration of counterparties may impact the company's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory, or other conditions.
The annual average gross balances of the company's options and contractual commitments used for trading purposes, based on month-end balances were as follows:
Average Fair Value ------------------------- 1997 Assets Liabilities - ----------- ------------------------- (in millions) Commodity instruments: Electricity $97 $94 Gas 6 6 Other 7 6
Average Fair Value ------------------------- 1996 Assets Liabilities - ----------- ------------------------- (in millions) Commodity instruments: Electricity $19 $18 Gas 1 1 Other - - - ----------------------------------------------------------------
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
Pension Plans
The system companies have defined benefit, trusteed, pension plans that cover substantially all regular employees. Benefits are based on one of the following formulas: years of service and final average pay or years of service and a flat-dollar benefit. Primarily, the companies use the "entry age normal method with a frozen initial liability" actuarial method for funding purposes, subject to limitations under federal income tax regulations. Amounts funded to the pension trusts are primarily invested in equity and fixed-income securities. FASB Statement No. 87, Employers' Accounting for Pensions, requires use of the "projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
In the United States, Southern Company provides certain medical care and life insurance benefits for retired employees. Substantially all these employees may become eligible for such benefits when they retire. The operating companies fund trusts to the extent deductible under federal income tax regulations or to the extent required by their respective regulatory commissions. Amounts funded are primarily invested in debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, requires that medical care and life insurance benefits for retired employees be accounted for on an accrual basis using a specified actuarial method, "benefit/years-of-service." In October 1993, the GPSC ordered Georgia Power to phase in the adoption of Statement No. 106 to cost of service over a five-year period, whereby one-fifth of the additional costs was expensed in 1993 and the remaining costs were deferred. An additional one-fifth of the costs was expensed each succeeding year until the costs were fully reflected in cost of service in 1997. The costs deferred during the five-year period will be amortized to expense over a 15-year period beginning in 1998. For the other operating companies, the cost of postretirement benefits is reflected in rates on a current basis.
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the Consolidated Balance Sheets at December 31 were as follows:
Pension ----------------------- 1997 1996 ----------------------- (in millions) Actuarial present value of benefit obligation: Vested benefits $ 2,891 $ 2,730 Non-vested benefits 83 119 - ------------------------------------------------------------------ Accumulated benefit obligation 2,974 2,849 Additional amounts related to projected salary increases 728 775 - ------------------------------------------------------------------ Projected benefit obligation 3,702 3,624 Less: Fair value of plan assets 5,953 5,258 Unrecognized net gain (1,877) (1,314) Unrecognized prior service cost 126 135 Unrecognized transition asset (101) (114) - ------------------------------------------------------------------ Prepaid asset recognized in the Consolidated Balance Sheets $ 399 $ 341 ==================================================================
Postretirement Benefits ---------------------------- 1997 1996 --------------- ------------ (in millions) Actuarial present value of benefit obligation: Retirees and dependents $477 $409 Employees eligible to retire 85 78 Other employees 373 383 - ------------------------------------------------------------------- Accumulated benefit obligation 935 870 Less: Fair value of plan assets 335 260 Unrecognized net loss (gain) 68 79 Unrecognized prior service cost (4) (5) Unrecognized transition obligation 233 249 - ------------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $303 $287 ===================================================================
The weighted average rates assumed in the actuarial calculations were:
1997 1996 1995 --------------------------------- Discount 7.5% 7.8% 7.3% Annual salary increase 5.0 5.3 4.8 Long-term return on plan assets 8.5 8.5 8.5 - -----------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.8 percent for 1997, decreasing gradually to 5.5 percent through the year 2005, and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated benefit obligation at December 31, 1997, by $80 million and the aggregate of the service and interest cost components of the net retiree cost by $7 million.
Components of the plans' net costs are shown below:
Pension --------------------------- 1997 1996 1995 --------------------------- (in millions) Benefits earned during the year $ 94 $ 99 $ 79 Interest cost on projected benefit obligation 271 267 193 Actual return on plan assets (856) (564) (730) Net amortization and deferral 417 152 412 - ------------------------------------------------------------------- Net pension cost (income) $ (74) $ (46) $ (46) ===================================================================
Of the above net pension income, $52 million in 1997, $37 million in 1996, and $30 million in 1995 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits --------------------------- 1997 1996 1995 --------------------------- (in millions) Benefits earned during the year $ 18 $ 20 $ 28 Interest cost on accumulated benefit obligation 67 60 67 Amortization of transition obligation 15 15 27 Actual return on plan assets (28) (17) (23) Net amortization and deferral 12 6 12 - ------------------------------------------------------------------ Net postretirement costs $ 84 $ 84 $111 ==================================================================
Of the above net postretirement costs, $70 million in 1997, $64 million in 1996, and $78 million in 1995 were charged to operating expenses, and $3 million in 1996 and $11 million in 1995 were deferred. The remainder for each year was charged to construction and other accounts.
Work Force Reduction Programs
The system companies have incurred additional costs for work force reduction programs. The costs related to these programs were $50 million, $85 million, and $42 million for the years 1997, 1996, and 1995, respectively. In addition, certain costs of these programs were deferred and are being amortized in
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accordance with regulatory treatment. The unamortized balance of these costs was $37 million at December 31, 1997.
3. LITIGATION AND REGULATORY MATTERS
Alabama Power Appliance Warranty Litigation
In 1996, legal actions against Alabama Power were filed in several counties in Alabama charging Alabama Power with fraud and non-compliance with regulatory statutes relating to the offer, sale, and financing of "extended service contracts" in connection with the sale of electric appliances. Some of these suits were filed as class actions, while others were filed on behalf of multiple individual plaintiffs. The plaintiffs seek damages for an unspecified amount. Alabama Power has offered extended service agreements to its customers since January 1984, and approximately 175,000 extended service agreements could be involved in these proceedings. The final outcome of these cases cannot now be determined.
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, 1997, Georgia Power had recorded approximately $5 million in expenses associated with the site. This represents Georgia Power'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 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.
Georgia Power Investment in Rocky Mountain
In its 1985 financing order, the GPSC concluded that completion of the Rocky Mountain pumped storage hydroelectric plant in 1991 as then planned was not economically justifiable and reasonable and withheld authorization for Georgia Power to spend funds from approved securities issuances on that plant. In 1988, Georgia Power and Oglethorpe Power Corporation (OPC) entered into a joint ownership agreement for OPC to assume responsibility for the construction and operation of the plant. The plant went into commercial operation in 1995.
In June 1996, the GPSC initiated a review of this plant. On January 14, 1998, the GPSC ordered that Georgia Power be allowed to include approximately $108 million of its $143 million investment in rate base as of December 31, 1998. Georgia Power has appealed the GPSC's order to the Superior Court of Fulton County, Georgia. If the order is upheld, Georgia Power will be required to record a write-off currently estimated to be approximately $29 million, after taxes.
The final outcome of this matter cannot now be determined. Accordingly, no provision related to the GPSC's disallowance has been recorded.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the reasonableness of the operating companies' wholesale rate schedules and contracts that have a return on common equity of 13.75 percent or greater. The contracts that could be affected by the hearings include substantially all of the transmission, unit power, long-term power, and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that changes in rate schedules and contracts were not necessary and that the FERC staff failed to show how any changes were in the public interest. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on substantially the same issues as in the 1991 proceeding. In November 1995, a FERC administrative law judge issued an opinion that the FERC staff failed to meet its burden of proof, and therefore, no change in the equity return was necessary. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were applied to all of the schedules and contracts involved in both proceedings -- as well as to certain other contracts that reference these proceedings in determining return on common equity -- and if refunds were ordered, the amount
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of refunds could range up to approximately $194 million at December 31, 1997. Although management believes that rates are not excessive and that refunds are not justified, the final outcome of this matter cannot now be determined.
Southern Company Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered into a settlement agreement related to tax issues for the years 1984 through 1987. The agreement is subject to the review and approval by the Joint Congressional Committee on Taxation. If approved by the Joint Committee, the agreement would resolve all issues in the case for the years before the U.S. Tax Court, resulting in a refund to Southern Company of approximately $162 million. This amount includes interest of $76 million. The tax litigation was related to a timing issue as to when taxes should have been paid; therefore, only the interest portion will affect future income. There can be no assurance that such Joint Committee approval will be received.
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 13.0 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 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.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
Georgia Power Retail Accounting Order
In February 1996, the GPSC approved a three-year accounting order, effective January 1, 1996. Under the accounting order, Georgia Power's earnings are evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Earnings in excess of 12.5 percent will be used to accelerate the amortization of regulatory assets or to accelerate the depreciation of electric plant. At its option, Georgia Power may also accelerate amortization or depreciation of assets while within the range allowed on common equity. Georgia Power is required to absorb cost increases of approximately $29 million annually during the three-year period, including $14 million annually of accelerated depreciation of electric plant. Under the accounting order, Georgia Power will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. On July 1, 1998, Georgia Power is required to file a general rate case. In response, the GPSC would be expected to either continue the provisions of the accounting order or adopt new ones.
A consumer group appealed the GPSC's decision to the Superior Court of Fulton County, Georgia. In 1996, the superior court ruled that statutory requirements applicable to rate cases were not followed and remanded the matter to the GPSC. In October 1997, the Georgia Court of Appeals upheld the accounting order and reversed the superior court's decision. This matter is now concluded.
4. CONSTRUCTION PROGRAM
The system companies are engaged in continuous construction programs, currently estimated to total some $2.0 billion in 1998, $2.0 billion in 1999, and $1.6 billion in 2000. 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; 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, 1997, significant purchase commitments were outstanding in connection with the construction program. The operating companies have approximately 1,600 megawatts of combined cycle generation scheduled to be placed in service by 2001. Southern Energy has under construction some 1,400
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
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, INVESTMENTS, AND COMMITMENTS
General
The amount and timing of additional equity capital to be raised in 1998 -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. Equity capital can be provided from any combination of public offerings, private placements, or the company's stock plans.
The operating companies' construction programs are expected to be financed primarily from internal sources. Short-term debt is often utilized and the amounts available are discussed below. The companies may issue additional long-term debt and preferred securities primarily for debt maturities and for redeeming higher-cost securities if market conditions permit.
Bank Credit Arrangements
At the beginning of 1998, unused credit arrangements with banks totaled $4.9 billion, of which $3.0 billion expires during 1998, $800 million during 1999 to 2001, and $1.0 billion during 2002. The following table outlines the credit arrangements by company:
Amount of Credit ----------------------------------------- Expires -------------------- 1999 & Company Total Unused 1998 beyond - ------------- ----------------------------------------- (in millions) Alabama Power $ 814 $ 814 $ 679 $ 135 Georgia Power 1,144 1,144 919 225 Gulf Power 103 94 94 - Mississippi Power 96 76 56 20 Savannah Electric 41 41 21 20 Southern Company 2,000 2,000 1,000 1,000 Southern Energy 1,038 635 193 442 Other 70 66 66 - ------------------------------------------ Total $5,306 $4,870 $3,028 $1,842 ==========================================
Approximately $2.1 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 Southern Company's credit facilities, $1.7 billion is a syndicated credit arrangement which also requires the payment of agent fees.
A portion of the $4.9 billion unused credit with banks is allocated to provide liquidity support to the companies' variable rate pollution control bonds. At December 31, 1997, the amount of the credit lines allocated for this purpose was $1.2 billion.
In addition, the companies from time to time borrow under uncommitted lines of credit with banks, and in the case of Southern Company, Alabama Power, Georgia Power, and Southern Energy, through commercial paper programs that have the liquidity support of committed bank credit arrangements.
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 subsidiaries.
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.
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Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated long-term obligations at December 31, 1997, were as follows:
Purchased Year Fuel Power - ----------- ------------------------------ (in millions) 1998 $ 2,081 $ 338 1999 1,596 164 2000 1,235 175 2001 1,122 178 2002 1,005 182 2003 and thereafter 4,580 1,720 - ------------------------------------------------------------- Total commitments $11,619 $2,757 =============================================================
Operating Leases
Southern Company has operating lease agreements with various terms and expiration dates. These expenses totaled $33 million, $23 million, and $17 million for 1997, 1996, and 1995, respectively. At December 31, 1997, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts - -------- ----------------- (in millions) 1998 $ 39 1999 37 2000 32 2001 28 2002 28 2003 and thereafter 291 - ------------------------------------------------------------- Total minimum payments $455 =============================================================
6. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
In 1992, Alabama Power sold an undivided interest in units 1 and 2 of Plant Miller and related facilities to Alabama Electric Cooperative, Inc.
Since 1975, Georgia Power has sold undivided interests in plants Vogtle, Hatch, Scherer, and Wansley in varying amounts, together with transmission facilities, to OPC, the Municipal Electric Authority of Georgia, and the city of Dalton, Georgia. 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, 1997, 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 ------------------- ------------------------------ Plant Vogtle (in millions) (nuclear) 45.7% $3,299 $1,100 Plant Hatch (nuclear) 50.1 840 477 Plant Miller (coal) Units 1 and 2 91.8 717 311 Plant Scherer (coal) Units 1 and 2 8.4 112 44 Plant Wansley (coal) 53.5 298 136 Rocky Mountain (pumped storage) 25.4 202 44 Intercession City (combustion turbine) 33.3 13 * - ------------------------------------------------------------------ *Less than $1 million.
Alabama Power and Georgia Power have contracted to operate and maintain the jointly owned facilities -- except for the Rocky Mountain project and Intercession City -- as agents for their respective co-owners. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the Consolidated Statements of Income.
7. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. These agreements -- expiring at various dates discussed below -- are firm and pertain to capacity related to specific generating units. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The capacity revenues amounted to $203 million in 1997, $217 million in 1996, and $237 million in 1995.
Unit power from specific generating plants is currently being sold to Florida Power & Light Company (FP&L), FPC, Jacksonville Electric Authority (JEA), and the city of Tallahassee, Florida. Under these agreements, approximately 1,600 megawatts of capacity is scheduled to be sold annually through 1999. Thereafter, these sales will decline to some 1,500 megawatts and
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
remain at that approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after 1999 with a minimum of three years notice -- until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1997, the tax-related regulatory assets and liabilities were $1.1 billion and $746 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:
1997 1996 1995 ----------------------------- (in millions) Total provision for income taxes: Federal -- Currently payable $ 547 $569 $ 567 Deferred -- current year 188 116 185 -- reversal of prior years (160) (74) (111) - -------------------------------------------------------------------- 575 611 641 - -------------------------------------------------------------------- State -- Currently payable 104 82 90 Deferred -- current year 15 23 26 -- reversal of prior years (19) (9) (12) - -------------------------------------------------------------------- 100 96 104 - -------------------------------------------------------------------- International - Windfall profits tax assessed in United Kingdom 148 - - Other 16 50 24 - -------------------------------------------------------------------- Total 839 757 769 Less income taxes charged (credited) to other income 114 10 (36) - -------------------------------------------------------------------- Total income taxes charged to operations $ 725 $747 $ 805 ====================================================================
The first half of the windfall profits tax assessed in the United Kingdom was paid in December 1997, and the remainder is due December 1998.
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:
1997 1996 --------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $3,345 $2,981 Property basis differences 1,756 2,154 Other 269 362 - ----------------------------------------------------------------- Total 5,370 5,497 - ----------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 108 110 Other property basis differences 245 253 Deferred costs 116 139 Pension and other benefits 72 68 Other 197 214 - ----------------------------------------------------------------- Total 738 784 - ----------------------------------------------------------------- Net deferred tax liabilities 4,632 4,713 Portion included in current assets, net 18 25 - ----------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheets $4,650 $4,738 =================================================================
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Consolidated Statements of Income. Credits amortized in this manner amounted to $30 million in 1997, $33 million in 1996, and $38 million in 1995. At December 31, 1997, 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:
1997 1996 1995 ------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.2 3.4 Non-deductible book depreciation 2.3 1.8 1.6 Windfall profits tax 8.0 - - Difference in prior years' deferred and current tax rate (1.5) (1.0) (1.1) Other (1.9) (0.5) 0.3 - ---------------------------------------------------------------------- Effective income tax rate 45.3% 38.5% 39.2% ======================================================================
Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
9. COMMON STOCK
Shares Reserved
At December 31, 1997, a total of 49 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
Southern Company's Executive Stock Option Plan was replaced by the Performance Stock Plan effective February 17, 1997. As of December 31, 1997, 283 current and former employees participated in the plan. The maximum number of shares of common stock that may be issued under the new plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. The first grant under the new plan was in July 1997. Options granted to date become exercisable pro rata over a maximum period of four years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the plan. Stock option activity in 1996 and 1997 for both plans are summarized below:
Shares Average Subject Option Price To Option Per Share ---------------------------------- Balance at December 31, 1995 2,476,299 $19.87 Options granted 1,460,731 23.00 Options canceled (13,878) 22.35 Options exercised (97,988) 17.94 - -------------------------------------------------------------------- Balance at December 31, 1996 3,825,164 21.11 Options granted 1,776,094 21.25 Options canceled (51,913) 21.83 Options exercised (137,426) 19.72 - -------------------------------------------------------------------- Balance at December 31, 1997 5,411,919 $21.18 ==================================================================== Shares reserved for future grants: At December 31, 1995 2,114,915 At December 31, 1996 668,062 At December 31, 1997 38,234,044 - -------------------------------------------------------------------- Options exercisable: At December 31, 1996 1,279,830 At December 31, 1997 1,996,724 - --------------------------------------------------------------------
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
In 1997, Southern Company adopted FASB Statement No. 128, Earnings per Share. This statement 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 -------------------------------------- 1997 1996 1995 -------------------------------------- (in thousands) As reported shares 685,033 672,590 665,064 Effect of options 191 200 170 -------------------------------------- Diluted shares 685,224 672,790 665,234 ======================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 1997, consolidated retained earnings included $3.8 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
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
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, 1997, preferred securities of $1.1 billion and capital securities of $600 million were outstanding. Southern Company guarantees the notes related to $600 million of capital securities issued on its behalf.
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1997 1996 -------------------- (in millions) Obligations incurred in connection with the sale by public authorities of pollution control revenue bonds: Collateralized -- 4.375% to 9.375% due 2000-2026 $1,154 $1,403 Variable rates (3.85% to 5.20% at 1/1/98) due 2011-2025 639 639 Non-collateralized -- 7.25% due 2003 1 1 6.75% to 8.375% due 2015-2020 109 200 5.8% due 2022 10 10 Variable rates (4.50% to 5.90% at 1/1/98) due 2021-2037 670 265 - ---------------------------------------------------------------- 2,583 2,518 - ---------------------------------------------------------------- Capitalized lease obligations 142 151 - ---------------------------------------------------------------- Long-term notes payable: 4% to 11% due 1997-2000 295 301 5.502% to 10.56% due 2001-2037 1,741 793 7.125% due 2047 194 - Adjustable rates (5.70% to 13% at 1/1/98) due 1997-2000 703 240 Adjustable rates (3.77% to 8.0781% at 1/1/98) due 2001-2007 1,533 81 - ---------------------------------------------------------------- 4,466 1,415 - ---------------------------------------------------------------- Total $7,191 $4,084 ================================================================
With respect to the collateralized pollution control revenue bonds, the operating companies have authenticated and delivered to trustees a like principal amount of first mortgage bonds as security for obligations under installment sale or loan agreements. The principal and interest on the first mortgage bonds will be payable only in the event of default under the agreements.
Sinking fund requirements and/or serial maturities through 2002 applicable to other long-term debt are as follows: $400 million in 1998; $610 million in 1999; $364 million in 2000; $323 million in 2001; and $939 million in 2002.
12. 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:
1997 1996 ---------------- (in millions) Bond improvement fund requirements $ 38 $ 40 Less: Portion to be satisfied by certifying property additions 3 4 - ----------------------------------------------------------------- Cash sinking fund requirements 35 36 First mortgage bond maturities and redemptions 349 76 Other long-term debt maturities (Note 11) 400 79 - ----------------------------------------------------------------- Total $784 $191 =================================================================
The first mortgage bond improvement (sinking) 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 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.
13. 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 $8.9 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 $79 million per incident for each licensed reactor it operates, but not more
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
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 $159 million and $160 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. The members are subject to a retrospective premium assessment in the event that losses exceed accumulated reserve funds. Alabama Power's and Georgia Power's maximum annual assessments are limited to $8 million and $10 million, respectively, under current primary policies.
Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can be insured against increased costs of replacement power in an amount up to $3.5 million per week -- starting 17 weeks after the outage -- for one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The maximum annual assessments under current policies for Alabama Power and Georgia Power for excess property damage would be $10 million and $11 million, respectively. The maximum replacement power assessments are $8 million for Alabama Power and $11 million for Georgia Power.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies issued or renewed on or after April 2, 1991, shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments -- whether generated for liability, property, or replacement power -- may be subject to applicable state premium taxes.
14. ACQUISITIONS
In 1997, Southern Energy acquired a 26 percent interest in an integrated utility in Berlin, Germany for approximately $820 million. Southern Energy also completed in 1997 the acquisition of a 100 percent interest in Consolidated Electric Power Asia (CEPA) for a total net investment of some $2.1 billion. CEPA is the largest independent power producer in Asia. The acquisition has been accounted for under the purchase method of accounting. The acquisition cost exceeded the fair market value of net assets by approximately $1.6 billion. This amount is considered goodwill and is being amortized on a straight-line basis over 40 years.
CEPA has been included in the consolidated financial statements since January 29, 1997. The following unaudited pro forma results of operations for the years 1997 and 1996 have been prepared assuming the acquisition of CEPA, effective January 1, 1996. The pro forma results assume acquisition financing of $716 million of short-term borrowings, $792 million of long-term notes, and $600 million of capital securities. Southern Company's assumed effective composite interest rate on these obligations for each period was 6.82 percent.
In 1995, Southern Energy acquired SWEB for approximately $1.8 billion. The British utility distributes electricity to some 1.3 million customers. The acquisition has been accounted for under the purchase method of accounting. Goodwill of $287 million is being amortized over 40 years. SWEB has been included in the consolidated financial statements since September 1995. The following pro forma results of operations for the year 1995 has been prepared assuming the acquisition of SWEB, effective January 1, 1994, and assuming 100 percent short-term debt financing.
These unaudited pro forma results are not necessarily indicative of the actual results that would have been realized had the acquisitions occurred on the assumed dates, nor are they necessarily indicative of future results. Pro forma operating results are for information purposes only and are as follows:
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Business Segments
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NOTES (continued) Southern Company and Subsidiary Companies 1997 Annual Report
Products and Services
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II-42C
II-43
II-44A
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II-46B
II-46C
II-47
II-48A
II-48B
II-48C
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II-52A
II-52B
II-52C
II-53
II-54A
II-54B
ALABAMA POWER COMPANY FINANCIAL SECTION
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MANAGEMENT'S REPORT Alabama Power Company 1997 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 11, 1998
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of 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, 1997 and 1996, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-65 through II-82) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
/s/Arthur Andersen LLP Birmingham, Alabama February 11, 1998
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 1997 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1997 net income after dividends on preferred stock was $376 million, representing a $4.4 million (1.2 percent) increase from the prior year. This improvement can be attributed primarily to lower non-fuel related operating expenses. Despite the mild weather experienced during 1997, retail sales increased approximately 2 percent. However, the expected net income effect was offset by reductions in certain industrial and commercial prices.
In 1996, earnings were $371 million, representing a 2.9 percent increase from the prior year. This increase was due to an increase in retail energy sales of 2.7 percent from 1995 levels and lower net interest charges compared to the prior year. This improvement was partially offset by a 4.4 percent increase in operating costs.
The return on average common equity for 1997 was 13.76 percent compared to 13.75 percent in 1996, and 13.61 percent in 1995.
Revenues
Operating revenues for 1997 were $3.1 billion, reflecting a 0.9 percent increase from 1996. The following table summarizes the principal factors that affected operating revenues for the past three years:
Increase (Decrease) From Prior Year -------------------------------------- 1997 1996 1995 -------------------------------------- (in thousands) Retail -- Growth and price change $ 33,813 $ 42,385 $ 19,164 Weather (22,973) (29,660) 54,888 Fuel cost recovery and other 31,353 (30,846) 35,235 ------------------------------------------------------------- Total retail 42,193 (18,121) 109,287 ------------------------------------------------------------- Sales for resale -- Non-affiliates 39,354 21,529 15,380 Affiliates (54,825) 88,890 (37,032) ------------------------------------------------------------- Total sales for resale (15,471) 110,419 (21,652) Other operating revenues 1,614 3,703 1,997 ------------------------------------------------------------- Total operating revenues $ 28,336 $ 96,001 $ 89,632 ------------------------------------------------------------- Percent change 0.9% 3.2% 3.1% =============================================================
Retail revenues of $2.5 billion in 1997 increased $42 million (1.7 percent) from the prior year, compared with a decrease of $18 million (0.7 percent) in 1996. Fuel revenues increased in 1997 due to slightly higher generation and higher fuel costs. This was the primary reason for the increase in 1997 retail revenues over 1996. Lower fuel cost recovery was the primary reason for the decrease in 1996 retail revenues as compared to 1995. 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.
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1997 Annual Report
and energy components were:
1997 1996 1995 ------------------------------------------- (in thousands)
Capacity $136,248 $150,797 $157,119 Energy 134,498 107,996 83,352 ---------------------------------------------------------- Total $270,746 $258,793 $240,471 ==========================================================
Capacity revenues from non-affiliates in 1997 decreased 9.6% compared to 1996 primarily due to a one-time unit power sales adjustment in 1997. Capacity revenues from non-affiliates were relatively constant in 1996 and 1995.
Kilowatt-hour (KWH) sales for 1997 and the percent change by year were as follows:
KWH Percent Change ----------- ------------------------------- 1997 1997 1996 1995 -------------------------------- ---------- (millions)
Residential 14,336 (1.8)% 1.5% 9.1% Commercial* 11,330 3.9 8.6 4.1 Industrial* 20,728 3.6 0.7 2.0 Other 181 (6.3) 3.1 0.5 ---------- Total retail 46,575 1.9 2.7 4.7 Sales for resale - Non-affiliates 11,894 25.3 18.0 18.8 Affiliates 8,993 (12.6) 53.5 (20.5) ---------- Total 67,462 3.0% 10.5% 2.6% - ----------------------------------------------------------------- *The KWH sales for 1996 reflect a reclassification of approximately 200 customers from industrial to commercial, which resulted in a shift of 473 million KWH. Absent the reclassification, the percentage change in KWH sales for commercial and industrial would have been 3.9% and 3.1%, respectively.
The increases in 1997 and 1996 retail energy sales were primarily due to the strength of business and economic conditions in the company's service area. Residential energy sales experienced a decline as a result of milder than normal weather in 1997, compared to relatively normal weather in 1996. Assuming normal weather, sales to retail customers are projected to grow approximately 2.3 percent annually on average during 1998 through 2003.
Expenses
Total operating expenses of $2.5 billion for 1997 were up $18 million or 0.7 percent compared with the prior year. This increase was primarily due to a $19 million increase in fuel costs and a $10 million increase in depreciation and amortization expense. These increases were somewhat offset by a $16 million decrease in maintenance expenses.
Total operating expenses of $2.5 billion for 1996 were up $105 million or 4.4 percent compared with 1995. The major components of this increase include $85 million in fuel costs, $15 million in maintenance expense, and $17 million in depreciation and amortization offset by a decrease in purchased power of $15 million.
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:
-------------------------- 1997 1996 1995 -------------------------- Total generation (billions of KWHs) 65 65 58 Sources of generation (percent) -- Coal 72 72 73 Nuclear 20 20 19 Hydro 8 8 8 Average cost of fuel per net KWH generated (cents) -- Coal 1.73 1.71 1.71 Nuclear 0.54 0.50 0.50 Total 1.49 1.46 1.48 - -------------------------------------------------------------- Note: Oil & Gas comprise less than 1% of generation.
Fuel expense increased in 1997 by $19 million or 2.2 percent. This increase can be attributed to slightly higher generation and fuel costs. Fuel expense increased in 1996 by $85 million or 10.8 percent. This increase can be attributed to higher generation.
Purchased power consists primarily of purchases from the affiliates of the Southern electric system. Purchased power transactions among the company and its
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1997 Annual Report
affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at each company. Total KWH purchases increased 12.4 percent from the prior year.
The 6.1 percent decrease in maintenance expenses in 1997 is attributable primarily to a decrease in distribution expenses. The increase in maintenance expenses for 1996 is due to increased nuclear expenses, primarily outage related accruals.
Depreciation and amortization expense increased 3.2 percent in 1997 and 5.6 percent in 1996. These increases reflect additions to utility plant.
Total net interest and other charges increased $25.4 million (11.2 percent) in 1997 primarily due to an increase in company obligated mandatorily redeemable preferred securities outstanding. This increase was offset by a $12 million (45.2 percent) decrease in dividends on preferred stock. The decline in net interest and other charges in 1996 by $11 million (4.5 percent) was due primarily to a charge of $10 million in 1995 to the amortization of debt discount, premium, and expense net, pursuant to an Alabama Public Service Commission (APSC) order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details.
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 long-lived utility plant. 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 stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors ranging from energy sales growth to a less regulated more competitive environment.
The company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the state of Alabama. Prices for electricity provided by the company to retail customers are set by the APSC under cost-based regulatory principles.
Future earnings in the near term will depend upon growth in electric sales, which are subject to a number of factors. Traditionally, these factors have included weather, competition, changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the company's service area. However, the Energy Policy Act of 1992 (Energy Act) is having a dramatic effect on the future of the electric utility industry. The Energy Act promotes energy efficiency, alternative fuel use, and increased competition for electric utilities. 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 a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell excess energy generation to other utilities. Also, electricity sales for resale rates are being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. The company is aggressively working to maintain and expand its share of wholesale business in the Southeastern power markets.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1997 Annual Report
change. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been or are being discussed in Alabama, Florida, Georgia, and Mississippi, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. The inability of the company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on the financial condition of the company. The company is attempting to minimize or reduce stranded cost exposure.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, unless the company remains a low-cost producer and provides quality service, the company's retail energy sales growth could be limited, and this could significantly erode earnings.
Rates to retail customers served by the company are regulated by the APSC. Rates for the company can be adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return. In June 1995, the APSC issued an order granting the company's request for gradual adjustments to move toward parity among customer classes. This order also calls for a moratorium on any periodic retail rate increases (but not decreases) until 2001.
In December 1995, the APSC issued an order authorizing the company to reduce balance sheet items -- such as plant and deferred charges -- at any time the company's actual base rate revenues exceed the budgeted revenues. In April 1997, the APSC issued an additional order authorizing the company to reduce balance sheet asset items. This order authorizes the reduction of such items up to an amount equal to five times the total estimated annual revenue reduction resulting from future rate reductions initiated by the company. See Note 3 to the financial statements for information about this and other matters.
The 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 of decommissioning costs for nuclear generating facilities in the financial statements. In response to these questions, the Financial Accounting Standards Board (FASB) has decided to review the accounting for liabilities related to closure and removal of long-lived assets, including nuclear decommissioning. If the FASB issues new accounting rules, the estimated costs of closing and removing 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 closure and removal 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 heavily dependent upon complex computer systems for all phases of its operations. The year 2000 issue -- common to most corporations - --concerns the inability of certain software and databases to properly recognize date sensitive information related to the year 2000 and thereafter. This problem could result in a material disruption to the company's operations, if not corrected. The company has assessed and developed a detailed strategy to prevent or at least minimize problems related to the year 2000 issue. In 1997 resources were committed and implementation began to modify the affected information systems. Total costs related to the project are estimated to be approximately $26 million, of which $2.1 million was spent in 1997. The remaining costs will be expensed primarily in 1998. Implementation is currently on schedule. Although, the degree of success of this project cannot be determined at this time, management believes there will be no significant effect on the company's operations.
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."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1997 Annual Report
The company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the company's operations is no longer subject to these provisions, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
Exposure to Market Risk
Due to cost-based rate regulation, the company has limited exposure to market volatility in interest rates and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1997, exposure from these activities was not material to the company's financial position, results of operations, or cash flows.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which will be effective in 1998. This statement establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. The objective of the statement is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners (comprehensive income). Comprehensive income is the total of net income and all other nonowner changes in equity. The company will adopt this statement in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an Enterprise and Related Information. This statement requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Generally, financial information is required to be reported on the basis that it is used by the chief operating decision maker in deciding how to allocate resources and in assessing performance. This statement also establishes standards for related disclosures about products and services, geographic areas, and major customers. The company adopted the new rules in 1997, and they did not have a significant impact on the company's financial reporting. However, this conclusion may change as industry restructuring and competitive factors influence the company's operations.
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1997. This stability is the continuation over recent years of growth in 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 $451 million in 1997. 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 44.7 percent in 1997, compared with 45.3 percent in 1996, and 45.0 percent in 1995.
In January 1997, Alabama Power Capital Trust II (Trust II), of which the company owns all of the common securities, issued $200 million of 7.60 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust II are $206 million aggregate principal amount of the company's 7.60 percent junior subordinated notes due December 31, 2036.
During 1997, the company redeemed $162.0 million of preferred stock and reacquired an additional $22.9 million through tender offer.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1997 Annual Report
The company's current securities ratings are as follows:
Duff & Standard Phelps Moody's & Poor's ---------------------------------- First Mortgage Bonds AA- A1 A+ Company Obligated Mandatorily Redeemable Preferred Securities A+ a2 A Preferred Stock A+ a2 A ------------------------------------------------------------
Capital Requirements
Capital expenditures are estimated to be $615 million for 1998, $723 million for 1999, and $524 million for 2000. The total is $1.9 billion for the three years. Actual capital costs may vary from this estimate because of factors such as changes in business conditions; revised load growth projections; changes in environmental regulations; changes in the existing nuclear plant to meet new regulatory requirements; increasing cost of labor, equipment, and materials; and cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
The company will replace all six steam generators at Plant Farley at a total cost of approximately $234 million. Additionally, the company plans to construct and install 800 megawatts of new generating capacity and associated substation facilities at Plant Barry. The projected capital expenditures for this project amount to approximately $289 million.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $320 million will be required by the end of 2000 for maturities of first mortgage bonds. Also, the company will continue to retire higher-cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law - significantly impacted the operating companies of Southern Company, including Alabama Power. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants are required in two phases. Phase I compliance began in 1995 and initially affected 28 generating units of Southern Company. As a result of Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Phase I compliance totaled approximately $25 million for the company.
For Phase II sulfur dioxide compliance, the company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as necessary to meet Phase II limits. Current compliance strategy for Phase II could require total estimated construction expenditures of approximately $33 million, of which $27 million remains to be spent.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. Also, in October 1997, the EPA issued a proposed regional ozone rule that --if implemented--could require substantial further reductions in NOx emissions from fossil-fueled generating facilities. Implementation of the standards and the proposed rule could result in significant additional compliance costs and capital expenditures that cannot be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: emission control strategies for ozone nonattainment areas; additional controls for hazardous air pollutant emissions; and hazardous waste disposal requirements. The impact of new standards will depend on the development and implementation of applicable regulations.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1997 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. The company conducts studies to determine the extent of any required cleanup costs and has recognized in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of Southern Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect Southern Company. The impact of new legislation -- if any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The company historically has relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control revenue bonds issued for its benefit by public authorities, to meet its long-term external financing requirements. Recently, the company's financings have consisted of unsecured debt and trust preferred securities. In this regard, the company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur. To issue additional debt and equity securities, the company must comply with certain earnings coverage requirements designated in its mortgage indenture and corporate charter. The company's coverages are at a level that would permit any necessary amount of security sales at current interest and dividend rates.
As required by the Nuclear Regulatory Commission and as ordered by the APSC, the company has established external trust funds for nuclear decommissioning costs. In 1994, the company also established an external trust fund for postretirement benefits as ordered by the APSC. The cumulative effect of funding these items over a long period will diminish internally funded capital and may require capital from other sources. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning."
Cautionary Statement Regarding Forward-Looking Information
The company's 1997 Annual Report contains forward-looking statements in addition to 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 statements; 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 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the company) is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The operating companies (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four southeastern states. Contracts among the companies -- dealing with jointly-owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC). The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern Communications provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Energy designs, builds, owns and operates power production and delivery facilities and provides a broad range of energy related services in the United States and international markets. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Company Energy Solutions develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The company is also subject to regulation by the FERC and the Alabama Public Service Commission (APSC). The company follows generally accepted accounting principles and complies with the accounting policies and practices prescribed by the respective regulatory 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.
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:
1997 1996 ----------------------- (in thousands) Deferred income taxes $ 384,549 $ 410,010 Deferred income tax credits (327,328) (364,792) Premium on reacquired debt 81,417 84,149 Department of Energy assessments 34,416 37,490 Vacation pay 28,783 28,369 Natural disaster reserve (22,416) (20,757) Work force reduction costs 19,316 45,969 Other, net 59,726 45,521 - ---------------------------------------------------------------- Total $ 258,463 $265,959 ================================================================
In the event that a portion of the company's operations is no longer subject to the provisions of Statement No. 71, the company would be required to write off related net regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The company accrues revenues for services rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The company's electric rates include provisions to adjust billings for fluctuations in fuel and the energy component of purchased power costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates.
The company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1997, uncollectible
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NOTES (continued) Alabama Power Company 1997 Annual Report
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 $68 million in 1997, $64 million in 1996, and $54 million in 1995. The company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel, which was scheduled to begin in 1998. However, the actual year this service will begin is uncertain. Sufficient storage capacity currently is available to permit operation into 2010 and 2013 at Plant Farley units 1 and 2, respectively.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a Uranium Enrichment Decontamination and Decommissioning Fund, which is to be funded in part by a special assessment on utilities with nuclear plants. This assessment will be paid over a 15- year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The company estimates its remaining liability at December 31, 1997, under this law to be approximately $34 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 3.3 percent in 1997 and 1996, and 3.2 percent in 1995. 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.
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations requiring all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The company has established external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over 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 -- at December 31, 1997, for Plant Farley were as follows:
Site study basis (year) 1993
Decommissioning periods: Beginning year 2017 Completion year 2029 ----------------------------------------------------------- (in millions) Site study costs: Radiated structures $ 489 Non-radiated structures 89 ----------------------------------------------------------- Total $ 578 =========================================================== (in millions) Ultimate costs: Radiated structures $1,504 Non-radiated structures 274 ----------------------------------------------------------- Total $1,778 =========================================================== (in millions) Amount expensed in 1997 $ 18 ----------------------------------------------------------- Accumulated provisions: Balance in external trust funds $ 193 Balance in internal reserves 44 ----------------------------------------------------------- Total $ 237 ===========================================================
Significant assumptions: Inflation rate 4.5% Trust earning rate 7.0 -----------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the APSC. All of the company's decommissioning costs are approved for ratemaking.
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NOTES (continued) Alabama Power Company 1997 Annual Report
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.
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 5.8 percent in 1997 and 1996, and 7.1 percent in 1995. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 0.8 percent in 1997, 1.1 percent in 1996 and 1.7 percent in 1995.
Utility Plant
Utility plant is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Financial Instruments
The company's only financial instruments for which the carrying amount did not approximate fair value at December 31 are as follows:
Carrying Fair Amount Value ------------------------- (in millions)
Long-term debt: At December 31, 1997 $2,541 $2,638 At December 31, 1996 $2,367 $2,420 Preferred Securities: At December 31, 1997 297 300 At December 31, 1996 97 94 ------------------------------------------------------------
The fair value for long-term debt and preferred securities was 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.
Natural Disaster Reserve
In September 1994, in response to a request by the company, the APSC issued an order allowing the company to establish a Natural Disaster Reserve. Regulatory treatment allows the company to accrue $250 thousand per month, until the maximum accumulated provision of $32 million is attained. However, in December 1995, the APSC approved higher accruals to restore the reserve to its authorized level whenever the balance in the reserve declines below $22.4 million.
2. RETIREMENT BENEFITS
Pension Plan
The company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. Benefits are based on one of the following formulas: years of service and final average pay or years of service and a flat-dollar benefit. The company uses the "entry age normal method with a frozen initial liability" actuarial method for funding purposes, subject to limitations under federal income tax regulations. Amounts funded to the pension trusts are primarily invested in equity and fixed-income securities. FASB Statement No. 87, Employers' Accounting for Pensions, requires use of the
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NOTES (continued) Alabama Power Company 1997 Annual Report
"projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
The company also provides certain medical care and life insurance benefits for retired employees. Substantially all these employees may become eligible for these benefits when they retire. Amounts funded are primarily invested in debt and equity securities. In December 1993, the APSC issued an accounting policy statement which requires the company to externally fund net annual postretirement benefits.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, requires that medical care and life insurance benefits for retired employees be accounted for on an accrual basis using a specified actuarial method, "benefit/years-of-service."
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the Balance Sheets at December 31 are as follows:
Pension ------------------- 1997 1996 ------------------- (in millions)
Actuarial present value of benefit obligations: Vested benefits $ 626 $ 603 Non-vested benefits 22 30 --------------------------------------------------------- Accumulated benefit obligation 648 633
Additional amounts related to projected salary increases 165 180 - ---------------------------------------------------------- Projected benefit obligation 813 813 Less: Fair value of plan assets 1,521 1,334 Unrecognized net gain (585) (413) Unrecognized prior service cost 43 46 Unrecognized transition asset (35) (40) - ---------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 131 $ 114 ==========================================================
Postretirement Benefits ---------------------- 1997 1996 ---------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $135 $116 Employees eligible to retire 24 28 Other employees 93 98 ----------------------------------------------------------- Accumulated benefit obligation 252 242 Less: Fair value of plan assets 135 108 Unrecognized net loss 3 15 Unrecognized transition obligation 61 65 ----------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 53 $ 54 ===========================================================
The weighted average rates assumed in the actuarial calculations were:
1997 1996 1995 -------------------------------
Discount 7.5% 7.8% 7.3% Annual salary increase 5.0 5.3 4.8 Long-term return on plan assets 8.5 8.5 8.5 ----------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.8 percent for 1997, decreasing gradually to 5.5 percent through the year 2005 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated benefit obligation as of December 31, 1997, by $21 million and the aggregate of the service and interest cost components of the net retiree cost by $2 million.
Components of the plans' net cost are shown below:
Pension ------------------------------------------------------------------- 1997 1996 1995 ----------------------------- (in millions) Benefits earned during the year $ 20.3 $ 21.5 $ 21.2 Interest cost on projected benefit obligation 58.4 59.5 54.3 Actual (return) loss on plan assets (227.8) (148.9) (236.3) Net amortization and deferral 116.8 43.8 136.9 ------------------------------------------------------------------- Net pension cost (income) $ (32.3) $ (24.1) $ (23.9) =====================================================================
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NOTES (continued) Alabama Power Company 1997 Annual Report
Of the above net pension income, $24.8 million in 1997, $20.3 million in 1996, and $17.1 million in 1995 were recorded as credits to operating expenses, and the remainder was recorded as credits to construction and other accounts.
Postretirement Benefits -------------------- 1997 1996 1995 ------------- ------ (in millions)
Benefits earned during the year $ 4 $ 5 $ 7 Interest cost on accumulated benefit obligation 18 17 18 Amortization of transition obligation 4 4 7 Actual (return) loss on plan assets (14) (7) (10) Net amortization and deferral 7 2 5 - ------------------------------------------------------------- Net postretirement costs $ 19 $ 21 $ 27 =============================================================
Of the above net postretirement costs recorded, $16.3 million in 1997, $17.8 million in 1996, and $22.7 million in 1995 were charged to operating expenses and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The company has incurred additional costs for work force reduction programs. The costs related to these programs were $33 million, $26.7 million and $14.3 million for the years 1997, 1996 and 1995, 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 $19.3 million at December 31, 1997.
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Procedures
In November 1982, the APSC adopted rates that provide for periodic adjustments based upon the company's earned return on end-of-period retail common equity. The rates also provide for adjustments to recognize the placing of new generating facilities in retail service. Both increases and decreases have been placed into effect since the adoption of these rates. The rate adjustment 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.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
Appliance Warranty Litigation
In 1996, legal actions against the company were filed in several counties in Alabama charging the company with fraud and non-compliance with regulatory statutes relating to the offer, sale, and financing of "extended service contracts" in connection with the sale of electric appliances. Some of these suits were filed as class actions, while others were filed on behalf of multiple individual plaintiffs. The plaintiffs seek damages for an unspecified amount. The company has offered extended service agreements to its customers since January 1984, and approximately 175,000 extended service agreements could be involved in these proceedings. The final outcome of these cases cannot now be determined.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the reasonableness of the operating companies' wholesale rate schedules and contracts that have a return on common equity of 13.75 percent or greater. The contracts that could be affected by the hearings include substantially all of the transmission, unit power, long-term power and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that changes in rate schedules and contracts were not necessary and that the FERC
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staff failed to show how any changes were in the public interest. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on substantially the same issues as in the 1991 proceeding. In November 1995, a FERC administrative law judge issued an opinion that the FERC staff failed to meet its burden of proof, and therefore, no change in the equity return was necessary. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were applied to all of the schedules and contracts involved in both proceedings, as well as certain other contracts that reference these proceedings in determining return on common equity, and if refunds were ordered, the amount of refunds could range up to approximately $194 million at December 31, 1997 for Southern Company, of which the company's portion would be approximately $95 million. Although management believes that rates are not excessive and that refunds are not justified, the final outcome of this matter cannot now be determined.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service entered into a settlement agreement related to tax issues for the years 1984 through 1987. The agreement is subject to the review and approval by the Joint Congressional Committee on Taxation. If approved by the Joint Committee, the agreement would resolve all issues in the case for the years before the U. S. Tax Court, resulting in a refund to the company of approximately $22 million. This amount includes interest of $14 million. The tax litigation was related to a timing issue as to when taxes should have been paid; therefore, only the interest portion will affect future income.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $615 million in 1998, $723 million in 1999, and $524 million in 2000. The capital budget is subject to periodic review and revision, and actual capital cost incurred may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth projections; changes in environmental regulations; changes in the existing nuclear plant to meet new regulatory requirements; increasing costs of labor, equipment, and materials; and cost of capital.
The company will replace all six steam generators at Plant Farley at a total cost of approximately $234 million. Additionally, the company plans to construct and install 800 megawatts of new generating capacity and associated substation facilities at Plant Barry. The projected capital expenditures for this project amount to approximately $289 million.
In addition, significant construction will continue related to transmission and distribution facilities and the upgrading of generating plants.
5. FINANCING, INVESTMENT, AND COMMITMENTS
General
To the extent possible, the company's construction program is expected to be financed primarily from internal sources. Short-term debt is often utilized and the amounts available are discussed below. The company may issue additional long-term debt and preferred securities for debt maturities, redeeming higher-cost securities, and meeting additional capital requirements.
Financing
The ability of the company to finance its capital budget depends on the amount of funds generated internally and the funds it can raise by external financing. The company historically has relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control revenue bonds issued for its benefit by public authorities, to meet its long-term external financing requirements. Recently, the company's financings have consisted of unsecured debt and trust preferred securities. In this regard, the company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur. In order to issue additional debt and equity securities, the company must comply with
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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, along with Georgia Power Company, has entered into agreements with several banks outside the service area to provide $300 million of revolving credit to the companies through June 30, 1999. To provide liquidity support for commercial paper programs, the company and Georgia Power Company have exclusive right to $135 million and $165 million, respectively, of the available credit. However, the allocations can be changed among the borrowers by notifying the respective banks. The companies have the option of converting the short-term borrowings 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 companies' option. In addition, these agreements require payment of commitment fees based on the unused portions of the commitments or the maintenance of compensating balances with the banks.
Additionally, the company maintains committed lines of credit in the amount of $679 million (including $208 million of such lines under which borrowings may be made only to fund purchase obligations relating to variable rate pollution control bonds) which expire at various times during 1998 and, in certain cases, provide for average annual compensating balances. Because the arrangements are based on an average balance, the company does not consider any of its cash balances to be restricted as of any specific date. Moreover, the company borrows from time to time pursuant to arrangements with banks for uncommitted lines of credit.
At December 31, 1997, 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, 1997, were as follows:
Year Amounts - ---- ----------------- (in millions) 1998 $869 1999 632 2000 388 2001 377 2002 317 2003-2013 2,538 - ------------------------------------------------------------- Total commitments $5,121 =============================================================
Operating Leases
The company has entered into coal rail car rental agreements with various terms and expiration dates. At December 31, 1997, estimated minimum rental commitments for noncancellable operating leases were as follows:
Year Amounts - ---- ----------------- (in millions) 1998 $5.6 1999 5.6 2000 5.6 2001 5.6 2002 5.6 2003-2017 55.5 - ------------------------------------------------------------------ Total minimum payments $83.5 ==================================================================
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
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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 company's share of expenses totaled $73 million in 1997, $75 million in 1996 and $71 million in 1995, and is included in "Purchased power from affiliates" in the Statements of Income.
In addition, the company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Georgia Power Company has agreed to reimburse the company for the pro rata portion of such obligation corresponding to its then proportionate ownership of stock of SEGCO if the company is called upon to make such payment under its guaranty.
At December 31, 1997, the capitalization of SEGCO consisted of $50 million of equity and $72 million of long-term debt on which the annual interest requirement is $4.5 million. SEGCO paid dividends totaling $10.6 million in 1997, $10.1 million in 1996, and $7.6 million in 1995, of which one-half of each was paid to the company. SEGCO's net income was $8.5 million, $7.7 million, and $8.1 million for 1997, 1996 and 1995, respectively.
The company's percentage ownership and investment in jointly-owned generating plants at December 31, 1997, 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 $ 93 $ 40 Plant Miller Units 1 and 2 717 311 - ------------------------------------------------------------
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 $136 million in 1997, $151 million in 1996, and $157 million in 1995.
Unit power from Plant Miller is being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority (JEA) and the City of Tallahassee, Florida. Under these agreements, approximately 1,200 megawatts of capacity is scheduled to be sold through 1999. Thereafter, these sales will remain at that approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after 1999 with a minimum of three years notice -- until the expiration of the contracts in 2010.
Alabama Municipal Electric Authority (AMEA) Capacity Contracts
In August 1986, the company entered into a firm power purchase 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 purchase 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
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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, 1997, $113.8 million of such bonds was held by the escrow agent under the contracts.
8. INCOME TAXES
At December 31, 1997, the tax-related regulatory assets and liabilities were $385 million and $327 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1997 1996 1995 ------------------------------------ (in thousands) Total provision for income taxes: Federal-- Currently payable $197,159 $172,911 $166,105 Deferred-- current year 32,884 (6,309) 43,493 reversal of prior years (44,300) 18,948 (15,817) Deferred investment tax credits - - (75) - ------------------------------------------------------------------------ 185,743 185,550 193,706 - ----------------------------------------------------------------------- State-- Currently payable 23,147 16,212 18,108 Deferred-- current year 1,409 697 5,117 reversal of prior years (2,422) 3,249 (91) - ------------------------------------------------------------------------ 22,134 20,158 23,134 Total 207,877 205,708 216,840 Less income taxes credited to other income (12,351) (22,400) (14,142) - ------------------------------------------------------------------------- Total income taxes charged operations $220,228 $228,108 $230,982 =========================================================================
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:
1997 1996 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $ 847 $ 816 Property basis differences 463 466 Premium on reacquired debt 30 31 Other 31 51 - ------------------------------------------------------------------ Total 1,371 1,364 - ------------------------------------------------------------------ Deferred tax assets: Capacity prepayments 31 34 Other deferred costs 33 27 Postretirement benefits 18 21 Unbilled revenue 16 15 Other 66 54 - ------------------------------------------------------------------ Total 164 151 - ------------------------------------------------------------------ Net deferred tax liabilities 1,207 1,213 Portion included in current assets (liabilities), net (15) (35) - ------------------------------------------------------------------ Accumulated deferred income taxes in the Balance Sheets $1,192 $1,178 ===================================================================
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Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $11 million in 1997 and 1996, and $12 million in 1995. At December 31, 1997, 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:
1997 1996 1995 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.4 2.2 2.5 Non-deductible book depreciation 1.5 1.5 1.6 Differences in prior years' deferred and current tax rates (2.3) (1.6) (1.8) Other (1.9) (3.0) (1.4) -------------------------------------------------------------- Effective income tax rate 34.7% 34.1% 35.9% ==============================================================
Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
9. COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES
In January 1996, Alabama Power Capital Trust I (Trust I), of which the company owns all of the common securities, issued $97 million of 7.375 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust I are $100 million aggregate principal amount of the company's 7.375 percent junior subordinated notes due March 31, 2026.
In January 1997, Alabama Power Capital Trust II (Trust II), of which the company also owns all of the common securities, issued $200 million of 7.60 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust II are $206 million aggregate principal amount of the company's 7.60 percent junior subordinated notes due December 31, 2036.
10. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1997 1996 -------------------------- (in thousands) Obligations incurred in connection with the sale of pollution control revenue bonds by public authorities- Collateralized - 5.5% to 6.5 % due 2023-2024 $223,040 $223,040 Variable rates (4.1% to 4.8% at 1/1/98) due 2015-2017 89,800 89,800 Non-collateralized - 7.25% due 2003 1,000 1,000 5.8% due 2022 9,800 9,800 Variable rates (4.50% to 5.9% at 1/1/98) due 2021 - 2022 217,500 152,500 - ------------------------------------------------------------- 541,140 476,140 Capitalized lease obligations 7,105 8,056 Long-term senior notes - 7.125% due 2047 193,800 - - ------------------------------------------------------------- Total $742,045 $484,196 =============================================================
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 $312.8 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.
The estimated aggregate annual maturities of other long-term debt through 2001 are as follows: $1.0 million in 1998, $1.2 million in 1999, $1.1 million in 2000, $1.0 million in 2001 and $1.1 million in 2002.
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NOTES (continued) Alabama Power Company 1997 Annual Report
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:
1997 1996 ------------------------ (in thousands) Bond improvement fund requirements $18,450 $ 19,410 First mortgage bond maturities and redemptions 55,895 391 Other long-term debt maturities (Note 10) 991 952 ------------------------------------------------------------ Total long-term debt due within one year 75,336 20,753 ------------------------------------------------------------ Preferred stock to be reacquired - 100,000 ------------------------------------------------------------ Total $75,336 $120,753 ============================================================
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. The 1998 requirement of $18.5 million was satisfied by the deposit of cash in 1998, all of which was used for the redemption of outstanding first mortgage bonds. Also in early 1998, the company redeemed $5.9 million first mortgage bonds and retired $50 million first mortgage bonds. Scheduled maturities amount to $991 thousand in connection with capitalized office building leases and a street light lease.
12. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (Act), the company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $8.9 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums which could be assessed, after a nuclear incident, against all owners of nuclear reactors. The company could be assessed up to $79 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 $159 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. The members are subject to a retrospective premium assessment in the event that losses exceed accumulated reserve funds. The company's maximum annual assessment per incident is limited to $8 million under the current policy.
Additionally, the company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional cost that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can be insured against increased cost of replacement power in an amount up to $3.5 million per week (starting 17 weeks after the outage) for one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The maximum annual assessments per incident under current policies for the company would be $10 million for excess property damage and $8 million for replacement power.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies issued or renewed on or after April 2, 1991, shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
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NOTES (continued) Alabama Power Company 1997 Annual Report
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, 1997, 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 1997 and 1996 are as follows: Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock ------------------- ----------------------------------------- (in thousands)
March 1997 $704,768 $123,455 $ 57,807 June 1997 728,089 125,750 63,137 September 1997 962,446 249,487 191,800 December 1997 753,808 128,511 63,195
March 1996 $732,809 $142,052 $ 73,159 June 1996 779,587 151,673 95,778 September 1996 913,308 222,523 152,589 December 1996 695,071 100,390 49,964 ---------------------------------------------------------------- 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 1997 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 four directors who are not employees, provides a broad overview of management's financial reporting and control functions. At least three times a year this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal control and financial reporting matters. The internal auditors and the independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted with a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of Georgia Power Company in conformity with generally accepted accounting principles.
/s/H. Allen Franklin H. Allen Franklin President and Chief Executive Officer
/s/Warren Y. Jobe Warren Y. Jobe Executive Vice President, Treasurer and Chief Financial Officer
February 11, 1998
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of 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, 1997 and 1996, and the related statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-108 through II-128) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
/s/Arthur Andersen LLP Atlanta, Georgia February 11, 1998
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 1997 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1997 earnings totaled $594 million, representing a $14 million (2.4 percent) increase over 1996. This earnings increase resulted primarily from lower operating expenses, lower financing costs, and increased non-operating income, partially offset by lower retail revenues and additional depreciation charges pursuant to a Georgia Public Service Commission (GPSC) retail accounting order discussed below. Earnings for 1996 totaled $580 million, representing a $29 million (4.7 percent) decrease from 1995. Earnings for 1995 included an after-tax gain of approximately $12 million from the completion of the sale of Plant Scherer Unit 4. The remaining decrease in 1996 earnings was primarily due to increased operating and maintenance expenses, partially offset by lower interest charges compared to the prior year.
Revenues
The following table summarizes the factors impacting operating revenues for the 1995-1997 period:
Increase (Decrease) From Prior Year ----------------------------------- 1997 1996 1995 ----------------------------------- Retail - (in millions) Sales growth $ 62 $ 58 $110 Weather (74) (25) 69 Fuel cost recovery (30) 28 66 Demand-side programs (3) (10) 36 - ------------------------------------------------------------------ Total retail (45) 51 281 - ------------------------------------------------------------------ Sales for resale - Non-affiliates 1 (9) (61) Affiliates 3 (41) 16 - ------------------------------------------------------------------ Total sales for resale 4 (50) (45) - ------------------------------------------------------------------ Other operating revenues 10 10 7 - ------------------------------------------------------------------ Total operating revenues $ (31) $ 11 $243 ================================================================== Percent change (0.7)% 0.3% 5.8% - ------------------------------------------------------------------
Retail revenues of $4 billion in 1997 decreased $45 million (1.1 percent) from 1996 primarily due to milder-than-normal weather, as well as commercial and industrial customers taking advantage of load management rates. Retail revenues in 1996 increased $51 million (1.3 percent) over the prior year primarily due to strong economic growth and an increase in sales to existing customers.
Fuel revenues generally represent the direct recovery of fuel expense, including the fuel component of purchased energy, and do not affect net income. Revenues from demand-side option programs generally represent the direct recovery of program costs. See Note 3 to the financial statements under "Demand-Side Conservation Programs" for further information on these programs.
Wholesale revenues from sales to non-affiliated utilities increased slightly in 1997 and were as follows:
1997 1996 1995 ------------------------------- (in millions) Outside service area - Long-term contracts $ 71 $ 84 $ 98 Other sales 80 37 25 Inside service area 132 161 168 - -------------------------------------------------------------- Total $283 $282 $291 ==============================================================
Contractual long-term sales to Florida utilities for 1997 and 1996 are down primarily due to scheduled reductions in the amount of capacity under those contracts. See Note 7 to the financial statements for further information regarding these sales. Revenues from other sales outside the service area increased in 1997 and 1996 primarily due to power marketing activities. Wholesale revenues from customers within the service area decreased in 1997 and 1996 primarily due to a decrease in revenues under a power supply agreement with Oglethorpe Power Corporation (OPC) and, in 1996, recognition of a refund to these customers. OPC decreased its purchases of capacity by 250 megawatts each in September 1996 and 1997 and has notified the Company of its intent to decrease purchases of capacity by an additional 250 megawatts in September 1998 and 1999.
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 1997 Annual Report
Kilowatt-hour (KWH) sales for 1997 and the percent change by year were as follows:
Percent Change --------------------------- KWH 1997 1996 1995 ------- ----------------------------- (in billions) Residential 17.3 (3.0)% 3.0% 10.4% Commercial 21.1 1.5 4.9 5.9 Industrial 26.7 1.9 3.6 3.9 Other 0.6 0.4 8.6 2.0 ------- Total retail 65.7 0.4 3.9 6.2 ------- Sales for resale - Non-affiliates 6.8 (13.6) 19.4 (17.3) Affiliates 1.7 44.6 (56.9) (10.4) ------- Total sales for resale 8.5 (6.0) (3.0) (15.4) ------- Total sales 74.2 (0.3) 3.0 2.8 =======
- ----------------------------------------------------------------
Residential sales declined 3.0 percent while sales to commercial and industrial customers increased slightly by 1.5 percent and 1.9 percent, respectively. Milder-than-normal temperatures experienced in 1997 contributed to the moderate sales. Residential, commercial and industrial energy sales growth in 1996 reflected strong economic growth and an increase in sales to existing customers.
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 kilowatt-hour generated were as follows:
1997 1996 1995 -------------------------- Total generation (billions of kilowatt-hours) 66.5 63.7 64.3 Sources of generation (percent) -- Coal 74.8 74.3 73.7 Nuclear 21.8 22.4 22.6 Hydro 2.7 2.7 3.0 Oil and gas 0.7 0.6 0.7 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.53 1.55 1.67 Nuclear 0.52 0.55 0.60 Oil and gas * * * Total 1.32 1.35 1.44 - --------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.
Fuel expense increased 2.6 percent in 1997 primarily due to an increase in generation, partially offset by a lower average cost of fuel. Fuel expense decreased 7.3 percent in 1996 because of a decrease in generation resulting from the timing of maintenance at nuclear plants and a lower average cost of fuel.
Purchased power expense decreased $66 million (17.1 percent) in 1997 primarily due to decreased purchases from affiliated companies and declines in contractual capacity buyback purchases from the co-owners of Plant Vogtle. Purchased power expense increased $72 million (22.8 percent) in 1996 primarily due to increased purchases from affiliated companies as a result of the timing of maintenance at nuclear plants discussed above. The increase in 1996 was partially offset by a decrease in energy purchases from wholesale customers within the service area and declines in the Plant Vogtle contractual capacity buyback purchases. Under the terms of the 1991 GPSC retail rate order, the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1997 Annual Report
declines in the Plant Vogtle contractual capacity buyback purchases were levelized over a six-year period ending September 1997. The levelization is reflected in the amortization of deferred Plant Vogtle costs in the Statements of Income. See Note 1 to the financial statements under "Plant Vogtle Phase-In Plans" for additional information.
Other operation and maintenance (O&M) expenses, excluding the provision for separation benefits, decreased 4.1 percent in 1997 primarily due to initiatives in 1996 to reduce fossil generation materials inventory levels and an adjustment in 1996 to deferred postretirement benefits to reflect changes in the retiree benefits plan. Other O&M expenses increased 2.9 percent in 1996 primarily as a result of the inventory initiatives and the adjustment to deferred postretirement benefits discussed above, and increased costs under a three-year retail accounting order effective January 1, 1996. See Note 3 to the financial statements under "Retail Accounting Order" for additional information.
Depreciation and amortization increased $140 million in 1997 and $11 million in 1996 primarily due to accelerated depreciation of generating plant pursuant to the retail accounting order and an increase in plant-in-service.
The Company has deferred certain expenses and recorded a deferred return related to Plant Vogtle under phase-in plans. The amortization of deferred Plant Vogtle costs reflects the completion in September 1997 of the amortization of the levelized buybacks and the Plant Vogtle Unit 1 cost deferrals under a 1987 GPSC order. See Note 1 to the financial statements under "Plant Vogtle Phase-In Plans" for information regarding the deferral and subsequent amortization of costs related to Plant Vogtle.
Other income increased in 1997 and decreased in 1996. The increase in 1997 is primarily due to increased tax benefits from losses of the parent company allocated to the Company under the joint consolidated income tax agreement between Southern Company and its subsidiaries. See Note 8 to the financial statements for additional information. The decrease in 1996 is primarily due to expenses in connection with the 1996 Summer Olympic games and the completion of the sale in 1995 of Plant Scherer Unit 4, which resulted in an after-tax gain of approximately $12 million.
Total financing costs decreased in 1997 and 1996. These changes were primarily due to the refinancing or retirement of securities. The Company refinanced or retired $701 million and $510 million of securities in 1997 and 1996, respectively. Interest and other charges increased $17 million (6.8 percent) and decreased $52 million (17.4 percent) in 1997 and 1996, respectively. While the issuance of additional mandatorily redeemable preferred securities in August 1996, January 1997 and June 1997 increased interest and other charges by $32 million and $6 million in 1997 and 1996, respectively, dividends on preferred stock decreased $26 million and $3 million in 1997 and 1996, respectively.
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 long-lived utility plant. 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 stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings. 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, 1996, the Company began operating under a three-year retail accounting order. Under the order, the Company's earnings are evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Earnings
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1997 Annual Report
in excess of 12.5 percent will be used to accelerate the amortization of regulatory assets or depreciation of electric plant. At its option, the Company may also recognize accelerated amortization or depreciation of assets within the allowed return on common equity range. The Company is required to absorb cost increases of approximately $29 million annually during the order's three-year operation, including $14 million annually of accelerated depreciation of electric plant. During the order's operation, the Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. Under the approved order, on July 1, 1998 the Company will make a general rate case filing in response to which the GPSC would be expected either to continue provisions of the accounting order or adopt different ones. See Note 3 to the financial statements under "Retail Accounting Order" for additional information.
Growth in energy sales is subject to a number of factors which traditionally have included changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, weather, competition, initiatives to increase sales to existing customers, and the rate of economic growth in the Company's service area. Assuming normal weather, retail sales growth is projected to be approximately 2 percent annually on average during 1998 through 2000.
Beginning in September 1997, OPC decreased its purchases of capacity under a power supply agreement by 250 megawatts and has notified the Company of its intent to decrease purchases of capacity by an additional 250 megawatts each in September 1998 and 1999. As a result, the Company's capacity revenues from OPC will decline by approximately $26 million in 1998, an additional $25 million in 1999, and an additional $18 million in 2000. Under the amended 1995 Integrated Resource Plan approved by the GPSC in March 1997, the resources associated with the decreased purchases in 1997 and 1998 will be used to meet the needs of the Company's retail customers through 2004.
The Company has entered into a 30-year purchase power agreement whereby the Company will buy electricity from a 300 megawatt cogeneration facility, starting in June 1998. Capacity and fixed O&M payments are projected to be $13 million in 1998, $14 million in 1999 and $14 million in 2000. The Company has also entered into a five-year purchase power agreement scheduled to begin in June 2000 for approximately 215 megawatts. Capacity and fixed O&M payments are estimated to be approximately $7 million in 2000.
The amortization of Plant Vogtle costs deferred under phase-in plans will decline by $89 million in 1998, $12 million in 1999, and $19 million in 2000. These costs will be fully amortized by September 1999. See Note 1 to the financial statements under "Plant Vogtle Phase-In Plans" for additional information.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate schedules and power sales contracts that the Company has with its sales for resale customers. The FERC currently is reviewing the rate of return on common equity included in these schedules and contracts and may require such returns to be lowered, possibly retroactively. See Note 3 to the financial statements under "FERC Review of Equity Returns" for additional information.
As discussed in Note 3 to the financial statements, regulatory uncertainties exist related to the Rocky Mountain pumped storage hydroelectric plant. On January 14, 1998, the GPSC ordered that the Company be allowed approximately $108 million of its $143 million investment in the plant in rate base as of December 31, 1998. The Company has appealed the GPSC's order. If such order is ultimately upheld, the Company will be required to record a charge to earnings currently estimated at approximately $29 million, after taxes.
Southern Company and the Internal Revenue Service (IRS) have entered into a settlement agreement that is subject to review and approval by the Joint Congressional Committee on Taxation. If approved, the agreement would result in a refund, including interest, to the Company. See Note 3 to the financial statements under "Tax Litigation" for additional information.
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 Issues."
The electric utility industry in the United States is currently undergoing a period of dramatic change as a result of regulatory and competitive factors.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1997 Annual Report
Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell electric energy to other utilities. Also, electricity sales for resale rates are being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. The Company is aggressively working to maintain and expand its share of wholesale sales in the Southeastern power markets. Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry.
The Company continues to compete with other electric suppliers within the state. In Georgia, most new retail customers with at least 900 kilowatts of connected load may choose their electricity supplier. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition across the nation. Among other things, these initiatives allow customers to choose their electricity provider. As these initiatives materialize, the structure of the utility industry could radically change. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While the GPSC has held workshops to discuss retail competition and industry restructuring, there has been no proposed or enacted legislation to date in Georgia. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of costs. The ability of the Company to recover all its costs, including the regulatory assets described in Note 1 to the financial statements, could have a material effect on the financial condition of the Company. The Company is attempting to reduce regulatory assets and other costs through a three-year retail accounting order. See Note 3 to the financial statements under "Retail Accounting Order" for additional information.
Unless the Company remains a low-cost producer and provides quality service, the Company's retail energy sales growth could be limited as competition increases. Conversely, continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation.
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry - including the Company's - regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating facilities in the financial statements. In response to these questions, the FASB has decided to review the accounting for liabilities related to closure and removal of long-lived assets, including nuclear decommissioning. If the FASB issues new accounting rules, the estimated costs of closing and removing 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 closure and removal 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 heavily dependent upon complex computer systems for all phases of its operations. The year 2000 issue -- common to most corporations -- concerns the inability of certain software and databases to properly recognize date sensitive information related to the year 2000 and thereafter. This problem could result in a material disruption to the Company's operations, if not corrected. The Company has assessed and developed a detailed strategy to prevent or at least minimize problems related to the year 2000 issue. In 1997 resources were committed and implementation began to modify the affected information systems. Total costs related to the project are estimated to be approximately $33 million, of which $3 million was spent in 1997. The remaining costs will be
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1997 Annual Report
expensed primarily in 1998. Implementation is currently on schedule. Although the degree of success of this project cannot be determined at this time, management believes there will be no significant effect on the Company's operations.
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, 1997, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which will be effective in 1998. This statement establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. The objective of the statement is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners (comprehensive income). Comprehensive income is the total of net income and all other nonowner changes in equity. The Company will adopt this statement in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an Enterprise and Related Information. This statement requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Generally, financial information is required to be reported on the basis that it is used by the chief operating decision maker in deciding how to allocate resources and in assessing performance. This statement also establishes standards for related disclosures about products and services, geographic areas, and major customers. The Company adopted the new rules in 1997, and they did not have a significant impact on the Company's financial reporting. However, this conclusion may change as industry restructuring and competitive factors influence the company's operations.
FINANCIAL CONDITION
Plant Additions
In 1997 gross utility plant additions were $476 million. These additions were primarily related to transmission and distribution facilities and to the purchase of nuclear fuel. The funds needed for gross property additions are currently provided from operations. The Statements of Cash Flows provide additional details.
Financing Activities
In 1997, the Company continued to lower its financing costs by refinancing higher-cost issues. New issues during 1995 through 1997 totaled $1.6 billion and retirement or repayment of securities totaled $2.2 billion. The retirements included the redemption of $131 million in 1995 of first mortgage bonds with the proceeds from the Plant Scherer Unit 4 sales. Composite financing rates for long-term debt and preferred stock for the years 1995 through 1997, as of year-end, were as follows:
1997 1996 1995 --------------------------------- Composite interest rate on long-term debt 6.11% 6.39% 6.57% Composite preferred stock dividend rate 5.18 6.34 6.73 - ----------------------------------------------------------------
The Company's current securities ratings are as follows:
Duff & Standard & Phelps Moody's Poor's ------------------------------------ First Mortgage Bonds AA- A1 A+ Preferred Stock A+ a2 A Unsecured Bonds A+ A2 A Commercial Paper D1+ P1 A1 - -----------------------------------------------------------------
Subsidiaries of the Company have issued mandatorily redeemable preferred securities. See Note 9 to the financial statements under "Preferred Securities" for additional information.
In January 1998, the Company issued $145 million of 6 7/8% unsecured senior notes due December 31, 2047. The senior notes are subordinated to all secured
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1997 Annual Report
debt of the Company, including its first mortgage bonds.
Liquidity and Capital Requirements
Cash provided from operations decreased by $15 million in 1997, primarily due to lower retail revenues.
The Company estimates that construction expenditures for the years 1998 through 2000 will total $506 million, $561 million and $549 million, respectively. Investments in transmission and distribution facilities, enhancements to existing generating plants, and equipment to comply with the provisions of the Clean Air Act are planned.
Cash requirements for improvement fund requirements, redemptions announced, and maturities of long-term debt and preferred stock are expected to total $693 million during 1998 through 2000.
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. For 1998 through 2000, the amount to be funded totals $24 million annually. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning."
Sources of Capital
The Company expects to meet future capital requirements primarily using funds generated from operations and, if needed, by the issuance of new debt and equity securities, term loans, and short-term borrowings. To meet short-term cash needs and contingencies, the Company had approximately $1.3 billion of unused credit arrangements with banks at the beginning of 1998. See Note 9 to the financial statements under "Bank Credit Arrangements" for additional information.
The Company historically has relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control revenue bonds issued for its benefit by public authorities, to meet its long-term external financing requirements. Recently, the Company's financings have consisted of unsecured debt and trust preferred securities. In this regard, the Company sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness it may incur.
If the Company chooses to issue first mortgage bonds or preferred stock, it is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter. The Company's ability to satisfy all coverage requirements is such that it could issue new first mortgage bonds and preferred stock to provide sufficient funds for all anticipated requirements.
Environmental Issues
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly impacted the operating companies of Southern Company, including Georgia Power. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants are required in two phases. Phase I compliance began in 1995 and initially affected 28 generating units in the Southern electric system. As a result of Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants in the Southern electric system will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected units by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Georgia Power's Phase I compliance totaled approximately $167 million.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as required to meet Phase II limits and ozone nonattainment requirements for metropolitan Atlanta through 2000. Current compliance strategy for Phase II and ozone nonattainment could require total estimated construction expenditures of approximately $39 million, of which $28 million remains to be spent as of December 31, 1997.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1997 Annual Report
provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. Also, in October 1997, the EPA issued a proposed regional ozone rule that --if implemented--could require substantial further reductions in NOx emissions from fossil-fueled generating facilities. Implementation of the standards and the proposed rule could result in significant additional compliance costs and capital expenditures that cannot be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: emission control strategies for ozone nonattainment areas; additional controls for hazardous air pollutant emissions; and hazardous waste disposal requirements. The impact of new standards will depend on the development and implementation of applicable regulations.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur costs to clean up properties currently or previously owned. 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, $2 million and $8 million, in 1997, 1996, and 1995, respectively. Additional sites may require environmental remediation for which the Company may be liable for a portion of or all required clean-up costs. See Note 3 to the financial statements under "Certain Environmental Contingencies" for information regarding the Company's potentially responsible party status at a site in Brunswick, Georgia, and the status of sites listed on the State of Georgia's hazardous site inventory.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time.
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 1997 Annual Report contains forward-looking statements in addition to 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 statements; 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 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, Southern Company Services (SCS), a system service company, Southern Communications Services (Southern Communications), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The operating companies (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four Southeastern states. Contracts among the operating companies -- dealing with jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC). SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern Communications provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Energy designs, builds, owns, and operates power production and delivery facilities and provides a broad range of energy related services in the United States and international markets. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Company Energy Solutions develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of this act. The Company is also subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). The Company follows generally accepted accounting principles (GAAP) and complies with the accounting policies and practices prescribed by the respective regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from these estimates.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Company's Balance Sheets at December 31 relate to the following:
1997 1996 ---------- --------- (in millions) -------------------- Deferred income taxes $ 688 $ 754 Deferred income tax credits (298) (318) Premium on reacquired debt 167 167 Corporate building lease 52 51 Deferred Plant Vogtle costs 50 171 Vacation pay 41 40 Postretirement benefits 38 38 Department of Energy assessments 29 32 Deferred nuclear outage costs 28 18 Demand-side program costs 11 44 Other, net 10 (9) - -------------------------------------------------------------- Total $ 816 $ 988 ==============================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related net regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
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NOTES (continued) Georgia Power Company 1997 Annual Report
Revenues and Fuel Costs
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 and the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1997, 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 $76 million in 1997, $78 million in 1996, and $86 million in 1995. The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel, which was scheduled to begin in 1998. However, the actual year this service will begin is uncertain. Sufficient storage capacity currently is available to permit operation into 2003 at Plant Hatch and into 2008 at Plant Vogtle. Activities for adding dry cask storage capacity at Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a Uranium Enrichment Decontamination and Decommissioning Fund, which is to be funded in part by a special assessment on utilities with nuclear plants. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The assessment will be paid over a 15-year period, which began in 1993. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company -- based on its ownership interests -- estimates its remaining liability under this law at December 31, 1997, to be approximately $27 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 3.1 percent in 1997 and 1996 and 3.2 percent in 1995. In addition, the Company recorded accelerated depreciation of electric plant of $159 million in 1997, $24 million in 1996, and $6 million in 1995. The amount of such charges in the accumulated provision for depreciation is $189 million at December 31, 1997. See Note 3 under "Retail Accounting Order" for additional information. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -- together with the cost of removal, less salvage -- is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected costs of decommissioning nuclear facilities and removal of other facilities.
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations requiring 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
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NOTES (continued) Georgia Power Company 1997 Annual Report
the retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs at December 31, 1997 -- based on the Company's ownership interests -- were 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 ============================================================
(in millions) Amount expensed in 1997 $ 11 $ 9
Accumulated provisions: Balance in external trust funds $118 $ 76 Balance in internal reserves 23 13 - ------------------------------------------------------------ Total $141 $ 89 ============================================================
Significant assumptions: Inflation rate 3.6% 3.6% Trust earnings rate 6.5 6.5 - ------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the GPSC. The decommissioning costs currently included in cost of service are $320 million and $267 million for plants Hatch and Vogtle, respectively. These amounts are based on the higher of the costs to decommission the radioactive portions of the plants based on 1994 site studies or the 1993 NRC minimum funding requirements. The estimated ultimate costs associated with the amounts currently included in cost of service are $781 million and $1.1 billion for plants Hatch and Vogtle, respectively. The Company expects the GPSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
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.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle, a two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased into rates. Pursuant to the orders, the Company recorded a deferred return under phase-in plans until October 1991 when the allowed investment was fully reflected in rates. In 1991, the GPSC levelized the remaining Plant Vogtle declining capacity buyback expenses over a six-year period. In addition, the Company deferred certain Plant Vogtle operating expenses and financing costs under accounting orders issued by the GPSC. These GPSC orders provide for the recovery of deferred costs within 10 years. Costs deferred under the 1987 order and the levelized buybacks were fully recovered as of September 1997.
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 1997, 1996 and 1995, the average AFUDC rates were 7.60 percent, 6.59 percent and 6.53 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 2.0 percent for 1997, 1996, and 1995.
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NOTES (continued) Georgia Power Company 1997 Annual Report
Utility Plant
Utility plant is stated at original cost with the exception of Plant Vogtle, which is stated at cost less regulatory disallowances. Original cost includes: materials; labor; payroll-related costs such as taxes, pensions, and other benefits; and the cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the 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 amounts did not approximate fair value at December 31 were as follows:
Carrying Fair Amount Value ------------------------ Long-term debt: (in millions) At December 31, 1997 $3,125 $3,170 At December 31, 1996 3,174 3,206 Preferred securities: At December 31, 1997 689 720 At December 31, 1996 325 333 - --------------------------------------------------------------
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
Pension Plan
The Company has a defined benefit, trusteed, non-contributory pension plan covering substantially all regular employees. Benefits are based on one of the following formulas: years of service and final average pay or years of service and a flat-dollar benefit. The Company uses the "entry age normal method with a frozen initial liability" actuarial method for funding purposes, subject to limitations under federal income tax regulations. Amounts funded to the pension trusts are primarily invested in equity and fixed-income securities. FASB Statement No. 87, Employers' Accounting for Pensions, requires use of the "projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
The Company also provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits when they retire. Qualified trusts are funded to the extent deductible under federal income tax regulations and to the extent required by the GPSC and the FERC. During 1997 and 1996, the Company funded $24 million and $25 million, respectively, to the qualified trusts. Amounts funded are primarily invested in debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, requires that medical care and life insurance benefits for retired employees be accounted for on an accrual basis using a specified actuarial method, "benefit/years-of-service." In October 1993, the GPSC ordered the Company to phase in the adoption of Statement No. 106 to cost of service over a five-year period, whereby one-fifth of the additional cost was expensed in 1993, and the remaining additional costs were deferred. An additional one-fifth of the costs were expensed each succeeding year until the costs were fully reflected in cost of service in 1997. The cost deferred during the five-year period will be amortized to expense over a 15-year period beginning in 1998.
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Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the Balance Sheets at December 31 are as follows:
Pension --------------------- 1997 1996 --------------------- (in millions) --------------------- Actuarial present value of benefit obligations: Vested benefits $ 841 $ 806 Non-vested benefits 29 52 - ---------------------------------------------------------------- Accumulated benefit obligation 870 858 Additional amounts related to projected salary increases 249 314 - --------------------------------------------------------------- Projected benefit obligation 1,119 1,172 Less: Fair value of plan assets 1,931 1,797 Unrecognized net gain (753) (591) Unrecognized prior service cost 48 56 Unrecognized transition asset (39) (47) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 68 $ 43 ===============================================================
Postretirement Benefits --------------------- 1997 1996 --------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $246 $217 Employees eligible to retire 33 29 Other employees 156 184 - --------------------------------------------------------------- Accumulated benefit obligation 435 430 Less: Fair value of plan assets 151 112 Unrecognized net loss 47 50 Unrecognized transition obligation 139 157 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 98 $111 ===============================================================
The weighted average rates used in actuarial calculations were:
1997 1996 1995 ---------------------------- Discount 7.5% 7.8% 7.3% Annual salary increase 5.0 5.3 4.8 Long-term return on Plan assets 8.5 8.5 8.5 - ----------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 8.8 percent for 1997, decreasing gradually to 5.5 percent through the year 2005 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated benefit obligation as of December 31, 1997, by $43 million and the aggregate of the service and interest cost components of the net postretirement cost by $4 million.
The components of the plans' net costs are shown below:
Pension ---------------------------- 1997 1996 1995 ---------------------------- (in millions) Benefits earned during the year $ 30 $ 35 $ 33 Interest cost on projected benefit obligation 82 86 78 Actual return on plan assets (301) (202) (317) Net amortization 161 62 185 - ----------------------------------------------------------------- Net pension benefit $ (28) $ (19) $ (21) =================================================================
Of net pension amounts recorded, $20 million in 1997, $14 million in 1996, and $15 million in 1995 were recorded as a reduction to operating expense, and the remainder was recorded as a reduction to construction and other accounts.
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Postretirement Benefits ------------------------- 1997 1996 1995 ------------------------- (in millions) Benefits earned during the year $ 7 $ 9 $13 Interest cost on accumulated benefit obligation 32 30 34 Amortization of transition obligation 9 9 16 Actual return on plan assets (8) (6) (8) Net amortization 2 3 4 - --------------------------------------------------------------- Net postretirement cost $42 $45 $59 ===============================================================
Of the above net postretirement benefit costs recorded, $32 million in 1997, $29 million in 1996, and $33 million in 1995 were charged to operating expenses. In addition, $3 million in 1996 and $11 million in 1995 were deferred, and the remainder was charged to construction and other accounts. During 1996, the Company expensed an additional $19 million due to an adjustment to amounts previously deferred under the GPSC order as a result of changes in the postretirement benefit plan.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs. The costs related to these programs were $5 million in 1997, $39 million in 1996 and $11 million in 1995. Additionally, the Company recognized $4 million in 1997, $9 million in 1996, and $3 million in 1995 for its share of costs associated with SCS's work force reduction programs.
3. REGULATORY AND LITIGATION MATTERS
Retail Accounting Order
On February 16, 1996, the GPSC approved a three-year accounting order for the Company. Under the order, effective January 1, 1996, the Company's earnings are evaluated against a retail return on common equity range of 10 percent to 12.5 percent. Earnings in excess of 12.5 percent will be used to accelerate the amortization of regulatory assets or depreciation of electric plant. At its option, the Company may also recognize accelerated amortization or depreciation of assets within the allowed return on common equity range. The Company is required to absorb cost increases of approximately $29 million annually during the order's three-year operation, including $14 million annually of accelerated depreciation of electric plant. During the order's operation, the Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. Under the approved order, on July 1, 1998, the Company will make a general rate case filing in response to which the GPSC would be expected either to continue the provisions of the accounting order or adopt different ones.
The Company's 1996 retail return on common equity was within the 10 percent to 12.5 percent range. During 1997, for earnings in excess of the 12.5% retail return, the Company recorded charges of $135 million that are presented in the financial statements as depreciation expense of electric plant and as an addition to the reserve for depreciation.
In November 1996, on appeal by a consumer group, the Superior Court of Fulton County, Georgia, reversed the GPSC's accounting order and remanded the matter to the GPSC. The Court found that statutory requirements applicable to rate cases should have been, but were not, followed. The GPSC and the Company subsequently appealed the Superior Court's decision. In October 1997, the Court of Appeals upheld the accounting order. No appeal of that decision was filed within the allowable time frame. The order stands as written, and this matter is now concluded.
FERC Review of Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the reasonableness of the Southern electric system's wholesale rate schedules and contracts that have a return on common equity of 13.75 percent or greater. The contracts that could be affected by the hearings include substantially all of the transmission, unit power, long-term power, and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that changes in rate schedules and contracts were not necessary and that the FERC staff failed to show how any changes were in the public interest. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on substantially the same issues as in the 1991 proceeding. In November 1995, a
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FERC administrative law judge issued an opinion that the FERC staff failed to meet its burden of proof, and therefore no change in the equity return was necessary. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were applied to all the schedules and contracts involved in both proceedings, as well as certain other contracts that reference these proceedings in determining return on common equity and if refunds were ordered, the amount of refunds could range up to approximately $71 million at December 31, 1997. Although management believes that rates are not excessive and that refunds are not justified, the final outcome of this matter cannot now be determined.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky Mountain pumped storage hydroelectric plant in 1991, as then planned, was not economically justifiable and reasonable and withheld authorization for the Company to spend funds from approved securities issuances on that plant. In 1988, the Company and Oglethorpe Power Corporation (OPC) entered into a joint ownership agreement for OPC to assume responsibility for the construction and operation of the plant, as discussed in Note 6. In 1995, the plant went into commercial operation.
In June 1996, the GPSC initiated a review of the plant. On January 14, 1998, the GPSC ordered that the Company be allowed approximately $108 million of its $143 million investment in the plant in rate base as of December 31, 1998. The Company has appealed the GPSC's order to the Superior Court of Fulton County, Georgia. If such order is ultimately upheld, the Company will be required to record a charge to earnings currently estimated at approximately $29 million, after taxes. The final outcome of this matter cannot now be determined. Accordingly, no provision related to the GPSC's disallowance has been recorded.
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 is subject to the review and approval by the Joint Congressional Committee on Taxation. If approved by the Joint Committee, the agreement would resolve all issues in the case for the years before the U. S. Tax Court, resulting in a refund to the Company of approximately $140 million. This amount includes interest of $61 million. The tax litigation was related to a timing issue as to when taxes should have been paid; therefore, only the interest portion will affect future income. There can be no assurance that such Joint Committee approval will be received.
Demand-Side Conservation Programs
In August 1995, the GPSC ordered the Company to discontinue its current demand-side conservation programs by the end of 1995. Rate riders previously approved by the GPSC for recovery of the Company's costs incurred in connection with these programs remained in effect until January 1998 when costs deferred were fully collected.
Under the Retail Accounting Order approved February 16, 1996, the Company will recognize approximately $29 million of deferred program costs over a three-year period which will not be recovered through the riders.
Certain Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by the EPA that they have been designated as potentially responsible parties under the Comprehensive Environmental Response, Compensation and Liability Act with respect to a site in Brunswick, Georgia. As of December 31, 1997, the Company has recognized approximately $5 million in 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
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list, the State identified several hundred properties throughout the State, including 25 sites which may require environmental remediation that were either previously or are currently owned by the Company. The majority of these sites are electrical power substations and power generation facilities. The Company has remediated nine electrical substations on the list at a cost of approximately $3 million. In addition, the Company has recognized approximately $17 million in expenses through December 31, 1997 for the assessment of the remaining sites on the list and the anticipated clean-up cost for 11 sites that the Company plans to remediate. Any cost of remediating the remaining sites cannot presently be determined until such studies are completed for each site and the State of Georgia determines whether remediation is required. If all listed sites were required to be remediated, the Company could incur expenses of up to approximately $15 million in additional clean-up costs and construction expenditures of up to approximately $65 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.
New Wholesale Agreement
On January 10, 1997, the Company and the Municipal Electric Authority of Georgia (MEAG) reached an agreement to enter into a new power supply relationship which would replace the partial requirements tariff pursuant to which the Company sells wholesale energy to MEAG and the scheduling services agreement between the Company and MEAG. The new power supply contract was approved by FERC and was implemented in August 1997.
Nuclear Performance Standards
In October 1989, the GPSC adopted a nuclear performance standard for the Company's nuclear generating units under which the performance of plants Hatch and Vogtle will be evaluated every three years. The performance standard is based on each unit's capacity factor as compared to the average of all comparable U.S. nuclear units operating at a capacity factor of 50 percent or higher during the three-year period of evaluation. Depending on the performance of the units, the Company could receive a monetary reward or penalty under the performance standards criteria.
The first evaluation was conducted in 1993 for performance during the 1990-92 period. The GPSC approved a performance reward of approximately $8.5 million for the Company. This reward was collected through the retail fuel cost recovery provision and recognized in income over a 36-month period which ended in October 1996. In January 1997, the GPSC approved a performance award of approximately $11.7 million for performance during the 1993-95 period. This reward is being collected through the retail fuel cost recovery provision and recognized in income over a 36-month period that began in January 1997.
4. COMMITMENTS
Construction Program
While the Company has no traditional baseload generating plants under construction, the construction of one jointly owned combustion turbine peaking unit was completed in January 1997. In addition, significant construction of transmission and distribution facilities, and projects to upgrade and extend the useful life of generating plants will continue. The Company currently estimates property additions to be approximately $506 million in 1998, $561 million in 1999, and $549 million in 2000. The estimates for property additions for the three-year period include $28 million committed to meeting the requirements of the Clean Air Act.
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.
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Total estimated long-term fossil and nuclear fuel commitments at December 31, 1997 were as follows: Minimum Year Obligations ---------------------- (in millions) 1998 $ 985 1999 799 2000 777 2001 673 2002 614 2003 and beyond 1,635 - --------------------------------------------------------------- Total minimum obligations $5,483 ===============================================================
Additional commitments for coal and for nuclear fuel will be required in the future to supply the Company's fuel needs.
Purchase Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed in Note 6, the Company has made commitments to purchase portions of OPC's and MEAG's capacity and energy from this plant. Declining commitments were in effect during periods of up to seven years following commercial operation and ended in 1996. As discussed in Note 1, the Plant Vogtle declining capacity buyback expense was levelized over a six-year period which ended in September 1997. In addition, the Company has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. Except as noted below, the cost of such capacity and energy is included in purchased power from non-affiliates in the Company's Statements of Income. Capacity payments totaled $54 million, $68 million, and $76 million in 1997, 1996, and 1995, respectively. The current projected Plant Vogtle capacity payments are:
Year Amounts ---------------------- (in millions) 1998 $ 57 1999 59 2000 62 2001 61 2002 60 2003 and beyond 771 - ---------------------------------------------------------------- Total $ 1,070 ================================================================
Portions of the payments noted above relate to costs in excess of Plant Vogtle's allowed investment for ratemaking purposes. The present value of these portions was written off in 1987 and 1990.
The Company and an affiliate, Alabama Power Company, own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of the units has been sold equally to the Company and Alabama Power 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:
1997 1996 1995 --------------------------------- (in millions) Energy $45 $47 $44 Capacity 30 30 29 - -------------------------------------------------------------- Total $75 $77 $73 ============================================================== Kilowatt-hours 3,038 2,780 2,391 - --------------------------------------------------------------
At December 31, 1997, 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 million.
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The Company has entered into other various long-term commitments for the purchase of electricity. Total long-term obligations at December 31, 1997 were as follows:
Year Amounts ---------------------- (in millions) 1998 $ 16 1999 17 2000 21 2001 22 2002 23 2003 and beyond 360 - --------------------------------------------------------------- Total $ 459 ===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $11 million for 1997 and 1996 and $12 million for 1995. At December 31, 1997, estimated minimum rental commitments for these noncancelable operating leases were as follows:
Year Amounts ---------------------- (in millions) 1998 $ 11 1999 11 2000 11 2001 12 2002 12 2003 and beyond 132 - --------------------------------------------------------------- Total $ 189 ===============================================================
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 $8.9 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 $79 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 $160 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. The members are subject to a retrospective premium assessment in the event that losses exceed accumulated reserve funds. The Company's maximum annual assessment is limited to $10 million under current policies.
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.
Additionally, NEIL covers the costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can be insured against increased costs of replacement power in an amount up to $3.5 million per week -- starting 17 weeks after the outage -- for one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The maximum annual assessments under the current policies for the Company would be $11 million for excess property damage and $11 million for replacement power.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies issued or renewed on or after April 2, 1991, shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining
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proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property or replacement power, may be subject to applicable state premium taxes.
6. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
The Company has sold undivided interests in plants Hatch, Wansley, Vogtle, and Scherer Units 1 and 2 to OPC, an electric membership generation and transmission corporation; MEAG, a public corporation and an instrumentality of the state of Georgia; and the City of Dalton, Georgia. The Company has sold an interest in Plant Scherer Unit 3 to Gulf Power Company, an affiliate. Additionally, the Company has sold 76.4 percent of Plant Scherer Unit 4 to Florida Power & Light Company (FP&L) and the remaining 23.6 percent to Jacksonville Electric Authority (JEA). The Company has also sold transmission facilities to Georgia Transmission Corporation (formerly OPC's transmission division), MEAG, and the City of Dalton.
Except as otherwise noted, the Company has contracted to operate and maintain all jointly owned facilities. The Company includes its proportionate share of plant operating expenses in the corresponding operating expenses in the Statements of Income.
As discussed in Note 3, the Company owns 25.4 percent of the Rocky Mountain pumped storage hydroelectric plant, which began commercial operation in 1995. OPC owns the remainder, and is the operator of the plant.
The Company owns six of eight 80 megawatt combustion turbine generating units and 75 percent of the related common facilities at Plant McIntosh. Savannah Electric and Power Company, an affiliate, owns the remainder and operates the plant. Four of the Company's six units began commercial operation during 1994, and the remaining two units began commercial operation in 1995.
The Company and Florida Power Corporation (FPC) jointly own a combustion turbine unit at Intercession City, Florida, near Orlando. The unit began commercial operation in January 1997, and is operated by FPC. The Company owns a one-third interest in the unit, with use of 100 percent of the unit's capacity from June through September. FPC has the capacity the remainder of the year.
At December 31, 1997, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation, were as follows:
Total Nameplate Company Facility (Type) Capacity Ownership - ------------------------------------------------------------------ (megawatts) Plant Vogtle (nuclear) 2,320 45.7% Plant Hatch (nuclear) 1,722 50.1 Plant Wansley (coal) 1,730 53.5 Plant Scherer (coal) Units 1 and 2 1,636 8.4 Unit 3 818 75.0 Plant McIntosh Common Facilities N/A 75.0 (combustion-turbine) Rocky Mountain 848 25.4 (pumped storage) Intercession City 142 33.3 (combustion-turbine) - ------------------------------------------------------------------
Accumulated Facility (Type) Investment Depreciation - ---------------------------------------------------------------- (in millions) Plant Vogtle (nuclear) $3,299* $1,100 Plant Hatch (nuclear) 840 477 Plant Wansley (coal) 298 136 Plant Scherer (coal) Units 1 and 2 112 44 Unit 3 542 164 Plant McIntosh Common Facilities (combustion-turbine) 19 1 Rocky Mountain (pumped storage) 202 44 Intercession City (combustion-turbine) 13 ** - ----------------------------------------------------------------
* Investment net of write-offs. ** Less than $1 million.
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7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of Southern Company have long-term contractual agreements for the sale of capacity and energy to non-affiliated utilities located outside the system's service area. These agreements consist of firm unit power sales pertaining to capacity from specific generating units. Because energy is generally sold at cost under these agreements, it is primarily the capacity revenues that affect the Company's profitability.
The Company's capacity revenues were as follows:
Year ------------------------------------- (in millions) (megawatts) 1997 $ 42 159 1996 41 173 1995 53 248 -------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA, and the City of Tallahassee, Florida. Under these agreements, the Company sold approximately 159 megawatts of capacity in 1997 and is scheduled to sell approximately 162 megawatts of capacity in 1998 and 1999. In 2000, 129 megawatts will be sold. After 2000, capacity sales will decline to approximately 105 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1997, tax-related regulatory assets were $688 million and tax-related regulatory liabilities were $298 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:
1997 1996 1995 ------------------------------- Total provision for income taxes: (in millions) Federal: Currently payable $ 352 $325 $349 Deferred - Current year 49 70 84 Reversal of prior years (68) (41) (55) Deferred investment tax credits - - 1 - ----------------------------------------------------------------- 333 354 379 - ----------------------------------------------------------------- State: Currently payable 65 56 60 Deferred - Current year 8 12 15 Reversal of prior years (11) (5) (8) - ----------------------------------------------------------------- 62 63 67 - ----------------------------------------------------------------- Total 395 417 446 - ----------------------------------------------------------------- Less: Income taxes credited to other income (32) (19) (3) - ----------------------------------------------------------------- Total income taxes charged to operations $ 427 $436 $449 =================================================================
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:
1997 1996 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,732 $1,736 Property basis differences 968 1,038 Other 142 174 - ----------------------------------------------------------------- Total 2,842 2,948 - ----------------------------------------------------------------- Deferred tax assets: Other property basis differences 216 225 Federal effect of state deferred taxes 99 100 Other deferred costs 83 93 Disallowed Plant Vogtle buybacks 23 24 Other 14 36 - ----------------------------------------------------------------- Total 435 478 - ----------------------------------------------------------------- Net deferred tax liabilities 2,407 2,470 Portion included in current assets 11 53 - ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $2,418 $2,523 =================================================================
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce
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depreciation in the Statements of Income. Credits amortized in this manner amounted to $15 million in 1997, $17 million in 1996, and $22 million in 1995. At December 31, 1997, 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:
1997 1996 1995 -------- -------- -------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 4 3 2 Other (4) (2) (1) - --------------------------------------------------------------- Effective income tax rate 39% 40% 40% ===============================================================
Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
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, 1997, $852 million of retained earnings and paid-in capital was unrestricted for the payment of cash dividends or any other distributions under terms of the mortgage indenture. If additional first mortgage bonds are issued, supplemental indentures in connection with those issues may contain more stringent restrictions than those currently in effect.
The Company's charter previously limited cash dividends on common stock to the lesser of the retained earnings balance or 75 percent of net income available for such stock during a prior period of 12 months if the ratio of common stock equity to total capitalization, including retained earnings, adjusted to reflect the payment of the proposed dividend, was below 25 percent, and to 50 percent of such net income if such ratio was less than 20 percent. These restrictions were removed by a vote of preferred shareholders on December 10, 1997.
Preferred Securities
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole general partner, issued $100 million of 9 percent mandatorily redeemable preferred securities. Substantially all of the assets of Georgia Power Capital are $103 million aggregate principal amount of Georgia Power's 9 percent Junior Subordinated Deferrable Interest Debentures due December 19, 2024.
Statutory business trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities as follows:
Date of Maturity Issue Amount Rate Notes Date ------------------------------------------------------- (millions) (millions) Trust I 8/1996 $225.00 7.75% $232 6/2036
Trust II 1/1997 175.00 7.60% 180 12/2036
Trust III 6/1997 189.25 7.75% 195 3/2037
Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above.
The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of Georgia Power Capital's and the Trusts' payment obligations with respect to the preferred securities.
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Georgia Power Capital, L.P., and the Trusts are subsidiaries of the Company, and accordingly are consolidated in the Company's financial statements.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public authorities of tax-exempt pollution control revenue bonds. The Company has authenticated and delivered to trustees an aggregate of $1.3 billion of its first mortgage bonds, which are pledged as security for its obligations under pollution control revenue contracts. No interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase or loan agreements.
Details of pollution control bonds are as follows:
Maturity Interest Rates 1997 1996 - -------------------------------------------------------------- (in millions) 2000 4.375% $ 50 $ 50 2004-2005 5% to 5.70% 104 143 2011 Variable 10 10 2017 8.375% to 9.375% - 140 2018-2022 6% to 6.35% & Variable 112 218 2023-2026 5.40% to 6.75% & Variable 1,110 1,110 2029-2032 Variable 235 - 2034 Variable 50 - - -------------------------------------------------------------- Total pollution control bonds $1,671 $1,671 ==============================================================
Senior Notes
In January 1998, the Company issued $145 million of 6 7/8% unsecured senior notes due December 31, 2047. The senior notes are subordinated to all secured debt of the Company, including its first mortgage bonds.
Bank Credit Arrangements
At the beginning of 1998, the Company had unused credit arrangements with banks totaling $1.3 billion, of which $919 million expires at various times during 1998, $300 million expires at June 30, 1999, and $60.3 million expires at May 1, 2000.
The $300 million expiring June 30, 1999, is under revolving credit arrangements with several banks providing the Company and Alabama Power Company up to a total credit amount of $300 million. To provide liquidity support for commercial paper programs, $165 million and $135 million are currently dedicated to the Company and Alabama Power Company, respectively. However, the allocations can be changed among the borrowers by notifying the respective banks.
Approximately $1.1 billion of the credit facilities allow for term loans of between one and three years. Most of the agreements include stated borrowing rates but also allow for negotiated rates. In addition, these agreements require payment of commitment fees based on the unused portions of the commitments or the maintenance of compensating balances with the banks.
Of the Company's total $1.3 billion in unused credit arrangements, a portion of the lines is dedicated to provide liquidity support to variable rate pollution control bonds. The credit lines dedicated as of December 31, 1997, totaled $879 million. In connection with all other lines of credit, the Company has the option of paying fees or maintaining compensating balances. These balances are not legally restricted from withdrawal.
In addition, the Company borrows under uncommitted lines of credit with banks and through a $225 million commercial paper program that has the liquidity support of committed bank credit arrangements. Average compensating balances held under these committed facilities were not material in 1997.
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, 1997 and 1996, 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.
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At December 31, 1997, and 1996, the interest and lease amortization deferred on the Balance Sheets are $52 million and $51 million, respectively.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company's fixed property and franchises.
Securities Due Within One Year
The current portion of the Company's long-term debt and preferred stock is as follows:
1997 1996 ------------------- (in millions) First mortgage bonds $ 220 $ 61 Preferred stock - 49 - ---------------------------------------------------------------- Total $ 220 $ 110 ================================================================
The Company's first mortgage bond indenture includes an improvement fund requirement that amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to January 1 of each year, other than those issued to collateralize pollution control obligations. The requirement may be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 2/3 times the requirement. The 1998 requirement was met in the first quarter of the year by depositing cash with the trustee. These funds were used to redeem first mortgage bonds.
Redemption of Securities
The Company plans to continue a program of redeeming or replacing debt and preferred stock in cases where opportunities exist to reduce financing costs. Issues may be repurchased in the open market or called at premiums as specified under terms of the issue. They may also be redeemed at face value to meet improvement fund requirements, to meet replacement provisions of the mortgage, or through use of proceeds from the sale of property pledged under the mortgage. 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 1997 and 1996 is as follows:
Net Income After Dividends on Operating Operating Preferred Quarter Ended Revenues Income Stock - ------------------------------------------------------------------- (in millions) -------------------------------------------- March 1997 $ 959 $180 $106 June 1997 1,015 205 131 September 1997 1,407 317 257 December 1997 1,005 159 100
March 1996 $1,029 $192 $114 June 1996 1,134 233 154 September 1996 1,311 339 256 December 1996 943 122 56 - -------------------------------------------------------------------
Earnings in the fourth quarter of 1997, compared to the fourth quarter of 1996, increased primarily as a result of higher retail sales and the recognition in 1996 of an agreement to refund $14 million to municipalities and cooperatives in Georgia.
The Company's business is influenced by seasonal weather conditions.
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GULF POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Gulf Power Company 1997 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 11, 1998
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of 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, 1997 and 1996, and the related statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-155 through II-171) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
/s/Arthur Andersen LLP Atlanta, Georgia February 11, 1998
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1997 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1997 net income after dividends on preferred stock was $57.6 million, a decrease of $0.2 million over the prior year. This change is primarily attributable to lower residential revenues as a result of milder than normal weather.
In 1996, earnings were $57.8 million, representing an increase of $0.6 million compared to the prior year. Earnings in 1996 were affected primarily by higher retail revenues.
The return on average common equity was 13.33 percent for 1997 and 13.27 percent for 1996.
Revenues
Operating revenues decreased in 1997 and increased in 1996 as a result of the following factors:
Increase (Decrease) From Prior Year ------------------------------------- 1997 1996 1995 ------------------------------------- (in thousands) Retail -- Sales growth $ 4,004 $ 7,123 $ 3,647 Weather (5,277) (1,057) 9,749 Regulatory cost recovery and other (7,837) 5,649 22,502 - ---------------------------------------------------------------- Total retail (9,110) 11,715 35,898 - ---------------------------------------------------------------- Sales for resale-- Non-affiliates 496 2,788 (5,698) Affiliates (1,002) (857) 1,266 - ---------------------------------------------------------------- Total sales for resale (506) 1,931 (4,432) Other operating revenues 1,107 1,642 8,798 - ---------------------------------------------------------------- Total operating revenues $(8,509) $15,288 $40,264 ================================================================ Percent change (1.3)% 2.5% 7.0% - ----------------------------------------------------------------
Retail revenues of $521 million in 1997 decreased $9.1 million or 1.7 percent from last year, compared with an increase of 2.3 percent in 1996 and 7.4 percent in 1995. The 1997 reduction was due primarily to a decrease in residential revenues as a result of mild weather and recovery of lower purchased power capacity costs.
The decrease in regulatory cost recovery and other retail revenues is primarily attributable to the recovery of decreased purchased power capacity costs from affiliated companies. 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 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 $80.5 million in 1997, decreasing $0.5 million or 0.6 percent from 1996. 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:
1997 1996 1995 ---------------------------------------- (in thousands) Capacity $24,899 $25,400 $25,870 Energy 18,160 19,804 18,598 - ------------------------------------------------------------ Total $43,059 $45,204 $44,468 ============================================================
Capacity revenues decreased slightly in 1997 and 1996, primarily reflecting the decline in net plant investment related to these sales.
Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales have little impact on earnings.
The increase in other operating revenues in 1997 is primarily attributable to adjustments to reflect differences between recoverable costs and the amounts actually reflected in current rates. The increase in other operating revenues for 1996 was primarily due to increased amounts collected to recover newly-imposed county franchise fees. These fees are included in taxes other than income taxes and have no impact on earnings. See Notes 1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery Clauses" and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1997 Annual Report
"Environmental Cost Recovery," respectively, for further discussion.
Kilowatt-hour sales for 1997 and percent changes in sales since 1995 are reported below.
KWH Percent Change ------------ --------------------------- 1997 1997 1996 1995 ------------ --------------------------- (millions) Residential 4,119 (1.0)% 3.6% 7.0% Commercial 2,898 3.2 3.7 6.3 Industrial 1,903 5.3 0.7 (2.8) Other 18 1.6 2.7 (0.1) ------------ Total retail 8,939 1.6 3.0 4.5 Sales for resale Non-affiliates 1,531 (0.2) 9.9 (1.6) Affiliates 848 19.5 (6.5) (13.1) ------------ Total 11,318 2.5 3.3 2.2 ==================================================================
Retail sales growth was lower in 1997 than in the past two years. Although the total number of residential customers served increased by more than 9,000 or 3.1% during the year, residential energy sales declined as a result of milder weather in 1997, compared with more normal weather in 1996. The increase in energy sales to the industrial class is primarily the result of the Real-Time-Pricing program. The price structure of this program has encouraged participating industrial customers to lower their peak demand requirements and increase their purchases of energy during off-peak periods. See "Future Earnings Potential" for information on the Company's initiatives to remain competitive and to meet conservation goals set by the Florida Public Service Commission (FPSC).
In 1997, energy sales for resale to non-affiliates were essentially unchanged, decreasing 0.2 percent, and are predominantly 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
In 1997, total operating expenses decreased $3.9 million or 0.7 percent from 1996 primarily due to lower fuel and purchased power expenses and maintenance expenses, offset by higher other operation expenses and depreciation and amortization expenses. Total operating expenses for 1996 increased $12.7 million or 2.4 percent from 1995. The increase is due to higher purchased power expenses, other operation expenses, depreciation expenses, and taxes.
In 1997, fuel and purchased power expenses decreased $10.1 million or 4.4 percent from 1996 reflecting the decrease in fuel and purchased power costs due to slightly lower fuel costs and increased generation. Fuel and purchased power expenses for 1996 increased $4 million or 1.8 percent from 1995. The change reflected the increase in purchased power from affiliated companies due to scheduled maintenance outages at Plant Crist and Plant Daniel during the first half of 1996. This increase was partially offset by a slight decrease in fuel expense reflecting a lower cost of fuel.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1997 1996 1995 ---------------------------- Total generation (millions of kilowatt-hours) 10,435 10,214 9,828 Sources of generation (percent) Coal 99.6 99.4 99.5 Oil and gas 0.4 0.6 0.5 Average cost of fuel per net kilowatt-hour generated (cents) Coal 1.97 1.99 2.08 Oil and gas 5.59 6.41 3.56 Total 1.99 2.02 2.09 - -----------------------------------------------------------------
Other operation expenses increased $11.1 million or 9.6% in 1997. The increase was primarily attributable to higher costs related to the amortization of prior year buyout and renegotiation of coal supply contracts. Other contributing factors were implementation costs related to a new customer accounting system and increased production and distribution costs related to 1997 work force reduction programs. In 1996, other operation expenses increased $1.8 million or 1.5 percent from the 1995 level. The increase was primarily attributable to an increase in administrative and general expenses including costs associated with the approved increase in the Company's annual accrual to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1997 Annual Report
the accumulated provision for property damage to amortize deferred storm charges and restore the account balance to a reasonable level. See Note 2 to the financial statements under "Workforce Reduction Programs" for further discussion.
Maintenance expenses decreased $3.1 million or 6.0 percent in 1997 and decreased $0.9 million or 1.7 percent in 1996. The decreases were primarily due to a decrease in scheduled maintenance of production facilities.
Depreciation and amortization expenses increased $1.2 million or 2.2 percent in 1997 and increased $1.5 million or 2.8 percent in 1996. Both years increases were primarily due to an increase in depreciation expenses as a result of an increase in the average investment in distribution property required to serve the additional customers in the Company's service area.
Federal and state income taxes decreased $2.8 million or 7.4 percent in 1997 primarily due to a decrease in taxable income.
Interest expense in 1997 decreased $0.9 million or 3.0 percent from the prior year. The decrease is attributable to retirements and refinancings of long-term debt and reduced interest on notes payable, partially offset by the increase related to distributions on preferred securities of a subsidiary trust. In 1996, interest expense increased $0.9 million or 3.2 percent over the prior year. The increase was attributable to the issuance of $30 million of new first mortgage bonds in January 1996. The increase in interest on long-term debt was partially offset by a decrease in interest on notes payable as a result of a lower average amount of short-term notes outstanding.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its 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 long-lived utility plant. 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 stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors ranging from energy sales growth to a potentially less regulated 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.
The electric utility industry in the United States is currently undergoing a period of change as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Company is positioning the business to meet the challenge of this major change in the traditional practice of selling electricity. The Energy Act allows independent power producers (IPPs) to access the Company's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for industrial and commercial customers and sell energy generation to other utilities. The Company has and will continue to evaluate opportunities to partner and participate in profitable cogeneration projects. In 1997, partnering with one of the Company's largest industrial customers, 15 megawatts of Company-owned cogeneration is being constructed 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1997 Annual Report
Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives to promote wholesale and retail competition are at varying stages. Among other things, these initiatives allow customers to choose their electricity provider. As the initiatives materialize, the structure of the utility industry could radically change. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been or are being discussed in Florida, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. The inability of the Company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on the financial condition of the Company. The Company is attempting to minimize or reduce its cost exposure.
Continuing to be a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, unless the Company remains a low-cost producer and provides quality service, the Company's retail energy sales growth could be limited, and this could significantly erode earnings.
The FPSC set conservation goals and approved programs to accomplish the goals beginning in 1995. The goals require conservation programs which reduce 154 megawatts of summer peak demand and 65 million KWH of sales by the year 2004. The Company can experience net growth as long as the filed programs achieve the intended reductions in peak demand and KWH sales. In response to these goals and seeking to remain competitive with other electric utilities, the Company has developed initiatives which emphasize price flexibility and competitive offering of energy efficiency products and services. These initiatives will enable customers to lower or alter their peak energy requirements. Besides promoting energy efficiency, another benefit of these initiatives could be the ability to defer the need to construct additional generating capacity.
On September 3, 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. During 1997, the publicity of the CISR ruling, increased competitive pressures, and general awareness of customer choice pilots and proposals across the country has 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 in 1997.
The Company is heavily dependent upon complex computer systems for all phases of its operations. The year 2000 issue--common to most corporations--concerns the inability of certain software and databases to properly recognize date sensitive information beginning related to the year 2000 and thereafter. This problem could result in a material disruption to the Company's operation, if not corrected. The Company has assessed and developed a detailed strategy to prevent or at least minimize problems related to the year 2000 issue. In 1997, resources were committed and implementation began to modify the affected information systems. Total costs related to the project for Southern Company are estimated to be approximately $85 million, of which $8 million was spent in 1997. The Company's total costs related to the project are estimated to be approximately $5 million, of which $0.5 million was spent in 1997. Most all remaining costs will be expensed in 1998. Implementation is currently on schedule and all costs are being expensed as incurred. The degree of success of this project cannot be determined at this time. However, management believes that the final outcome will not have a material adverse effect on the operations of the Company.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1997 Annual Report
Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters." 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, 1997, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which will be effective in 1998. This statement establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. The objective of the statement is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners (comprehensive income). Comprehensive income is the total of net income and all other non-owner changes in equity. These rules will be adopted by the Company in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an Enterprise and Related Information. This statement requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Generally, financial information is required to be reported on the basis that it is used by the chief operating decision maker in deciding how to allocate resources and in assessing performance. This statement also establishes standards for related disclosures about products and services, geographic areas, and major customers. The Company adopted the new rules in 1997, which do not have a significant impact on the Company's financial reporting. However, this conclusion may change as industry restructuring and competitive factors influence the Company's operations.
FINANCIAL CONDITION
Overview
The Company's financial condition continues to be very solid. During 1997, gross property additions were $54.3 million. Funds for the property additions were provided by internal sources. See the Statements of Cash Flows for further details.
Financing Activities
The Company continued to lower its financing costs by issuing new long term-notes and trust preferred securities and retiring higher-cost issues in 1997. The Company sold $40 million of trust preferred securities, $40.9 million of pollution control bonds, and $20 million of junior subordinated notes. Retirements, including maturities during 1997, totaled $25 million of first mortgage bonds, $40.9 million of pollution control bonds, $75.9 million of preferred stock, and $16 million of long-term bank notes. The refinancing of $40.9 million in pollution control bonds and $39.5 million in preferred stock will result in savings of over $2.6 million annually. See the Statements of Cash Flows for further details.
Composite financing rates for the years 1995 through 1997 as of year end were as follows:
1997 1996 1995 ------------------------------ Composite interest rate on long-term debt 5.9% 6.1% 6.5% Composite preferred stock dividend rate 6.1% 6.4% 6.4% - ----------------------------------------------------------------
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1997 Annual Report
The decrease in the composite interest rate on long-term debt from 1995 to 1997 reflects the Company's efforts to refinance higher-cost debt. The decrease in the composite preferred stock dividend rate in 1997 was primarily due to a decrease in dividends on the Company's adjustable rate preferred stock, reflecting lower interest rates, and the retirement of higher coupon rate preferred stock.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $192 million for the three years beginning in 1998 ($68 million in 1998, $62 million in 1999, and $62 million in 2000). Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The Company does not have any major generating plants under construction, however, significant construction related to maintaining and upgrading transmission and distribution facilities and generating plants will continue.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $80 million will be required by the end of 2000 in connection with maturities of long-term debt. Also, the Company will continue to retire higher-cost debt and preferred stock 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 could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as required to meet Phase II limits. Current compliance strategy for Phase II and ozone non-attainment could require total estimated construction expenditures for Southern Company of approximately $70 million, of which $55 million remains to be spent. Phase II compliance is not expected to have a material impact on Gulf Power.
Following adoption of legislation in April of 1992 allowing electric utilities in Florida to seek FPSC approval of their Clean Air Act Compliance Plans, Gulf Power filed its petition for approval. The FPSC approved the Company's plan for Phase I compliance, deferring until a later date approval of its Phase II Plan.
In 1993, the Florida Legislature adopted legislation that allows a utility to petition the FPSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The legislation is discussed in Note 3 to the financial statements under "Environmental Cost Recovery." Substantially all of the costs for the Clean Air Act and other new environmental legislation discussed below are expected to be recovered through the Environmental Cost Recovery Clause.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. Also, in October 1997, the EPA issued a proposed regional ozone rule--if implemented--that could require substantial further reductions in NOx emissions from fossil-fueled generating facilities. Implementation of the standards and the proposed rule could result in significant additional compliance costs and capital expenditures that cannot be determined at this time.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1997 Annual Report
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; and hazardous waste disposal requirements. The impact of new standards will depend on the development and implementation of applicable regulations.
Gulf Power must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup costs and has recognized in the financial statements costs to clean up known sites. For additional information, see Note 3 to the financial statements under "Environmental Cost Recovery."
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change, electric and magnetic fields, and other environmental health concerns could significantly affect the Company. The impact of new legislation -- if any - -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electric and magnetic fields.
Sources of Capital
At December 31, 1997, the Company had $4.7 million of cash and cash equivalents and $32.5 million of unused committed lines of credit with banks to meet its short-term cash needs. Refer to 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.
In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company owns all the common securities, issued $45 million of 7.0 percent mandatorily redeemable preferred securities. See Note 9 to the financial statements under "Company Obligated Mandatorily Redeemable Preferred Securities" for additional information.
It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived from operations; the sale of additional first mortgage bonds, long-term unsecured debt, pollution control bonds, and preferred securities; bank notes; and capital contributions from Southern Company. If the attractiveness of current short-term interest rates continues, the Company may maintain a higher level of short-term indebtedness than has historically been true. The Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's coverage ratios are sufficient to permit, at present interest and preferred dividend levels, any foreseeable security sales. In December 1997, the Company obtained stockholder approval to amend the corporate charter including the elimination of the restrictions on the amount of unsecured indebtedness allowed. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.
Cautionary Statement Regarding Forward-Looking Information
Gulf Power Company's 1997 Annual Report contains forward-looking statements in addition to 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 statements; 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1997 Annual Report
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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STATEMENTS OF INCOME For the Years Ended December 31, 1997, 1996, and 1995 Gulf Power Company 1997 Annual Report
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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Gulf Power Company is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The operating companies (Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric) provide electric service in four southeastern states. Gulf Power Company provides electric service to the northwest panhandle of Florida. Contracts among the operating companies -- dealing with jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern Communications provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Company Energy Solutions develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Florida Public Service Commission (FPSC). The Company follows generally accepted accounting principles and complies with the accounting policies and practices prescribed by the FPSC. The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates, and the actual results may differ from those estimates.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following:
1997 1996 ------------------------- (in thousands) Deferred income tax debits $ 26,586 $ 28,313 Deferred loss on reacquired debt 20,494 20,386 Environmental remediation 7,338 7,577 Current & deferred coal contract costs 4,456 29,515 Vacation pay 4,057 4,055 Deferred storm charges 703 3,275 Regulatory clauses over recovery, net (3,387) (1,740) Deferred income tax credits (56,935) (64,354) Other, net (629) (1,202) - ----------------------------------------------------------------- Total $ 2,683 $ 25,825 =================================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related net regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value.
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NOTES (continued) Gulf Power Company 1997 Annual Report
Revenues and Regulatory Cost Recovery Clauses
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. In 1997, uncollectible accounts continued to average significantly less than 1 percent of revenues.
Fuel costs are expensed as the fuel is used. The Company's electric rates include provisions to periodically adjust billings for fluctuations in fuel, the energy component of purchased power costs, and certain other costs. The Company also has similar cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted monthly for differences between recoverable costs and amounts actually reflected in current rates.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.6 percent in 1997, 1996, and 1995. 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 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. The Company is included in the consolidated federal income tax return of Southern Company. See Note 8 for further information related to income taxes.
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. AFUDC amounts for 1997, 1996, and 1995 were immaterial and are included in other, net and other interest charges in the Statements of Income.
Utility Plant
Utility plant is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
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 thousands) Long-term debt At December 31, 1997 $350,320 $356,766 At December 31, 1996 $372,852 $373,394
Capital trust preferred securities: At December 31, 1997 $40,000 $40,800 At December 31, 1996 - - - -------------------------------------------------------------
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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 $1.4 million and $1.8 million at December 31, 1997 and 1996, respectively, is included in miscellaneous current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
The Company is self-insured for the full cost of storm and other damages to its transmission and distribution property. At December 31, 1997, the accumulated provision for property damage had a negative balance of $0.7 million. The negative balance was reclassified to deferred storm charges in the accompanying Balance Sheets. In December 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 million. The FPSC has also given the Company the flexibility to increase its annual accrual amount above $3.5 million, when the Company believes it is in a position to do so, until the account balance reaches $12 million. The Company accrued $3.9 million in 1997 and $4.5 million in 1996 to the accumulated provision for property damage. The expense of repairing damages from major storms and other uninsured property damages is charged to the provision account.
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. Benefits are based on one of the following formulas: years of service and final average pay or years of service and a flat-dollar benefit. The Company uses the "entry age normal method with a frozen initial liability" actuarial method for funding purposes, subject to limitations under federal income tax regulations. Amounts funded to the pension trust fund are primarily invested in equity and fixed-income securities. FASB Statement No. 87, Employers' Accounting for Pension, requires use of the "projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
The Company provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits when they retire. Trusts are funded to the extent deductible under federal income tax regulations or to the extent required by the Company's regulatory commissions. Amounts funded are primarily invested in equity and fixed-income securities. FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, requires that medical care and life insurance benefits for retired employees be accounted for on an accrual basis using a specified actuarial method, "benefit/years-of-service."
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Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the Balance Sheets at December 31 are as follows:
Pension ------------------------- 1997 1996 ------------------------- (in thousands) Actuarial present value of benefit obligation: Vested benefits $ 97,180 $ 87,245 Non-vested benefits 3,886 5,101 - ------------------------------------------------------------- Accumulated benefit obligation 101,066 92,346 Additional amounts related to projected salary increases 29,728 31,121 - ------------------------------------------------------------- Projected benefit obligation 130,794 123,467 Less: Fair value of plan assets 222,196 191,152 Unrecognized net gain (80,497) (58,900) Unrecognized prior service cost 5,244 5,618 Unrecognized transition asset (5,764) (6,485) - ------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 10,385 $ 7,918 =============================================================
Postretirement Benefits --------------------------- 1997 1996 --------------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $17,363 $10,478 Employees eligible to retire 4,537 5,484 Other employees 17,769 17,694 - ---------------------------------------------------------------- Accumulated benefit obligation 39,669 33,656 Less: Fair value of plan assets 9,813 7,996 Unrecognized net loss 3,930 1,531 Unrecognized transition obligation 5,435 5,790 - ---------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $20,491 $18,339 ================================================================
The weighted average rates assumed in the actuarial calculations were:
1997 1996 1995 ------------------------------ Discount 7.5% 7.8% 7.3% Annual salary increase 5.0% 5.3% 4.8% Long-term return on plan assets 8.5% 8.5% 8.5% - -----------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.8 percent for 1997, decreasing gradually to 5.5 percent through the year 2005 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated benefit obligation at December 31, 1997, by $3.2 million and the aggregate of the service and interest cost components of the net retiree cost by $278 thousand.
Components of the plans' net costs are shown below:
Pension ------------------------------------ 1997 1996 1995 ------------------------------------ (in thousands) Benefits earned during the year $ 3,897 $ 3,880 $ 3,867 Interest cost on projected benefit obligation 9,301 9,129 8,042 Actual (return) loss on plan assets (32,924) (21,021) (33,853) Net amortization and deferral 17,246 5,920 19,619 - ------------------------------------------------------------------ Net pension income $ (2,480) $ (2,092) $(2,325) ==================================================================
Of the above net pension amounts, pension income of $1.8 million in 1997, $1.5 million in 1996, and $1.8 million in 1995 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
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NOTES (continued) Gulf Power Company 1997 Annual Report Postretirement Benefits -------------------------------- 1997 1996 1995 -------------------------------- (in thousands) Benefits earned during the year $ 896 $ 939 $1,259 Interest cost on accumulated benefit obligation 2,845 2,330 2,520 Amortization of transition obligation 356 356 853 Actual (return) loss on plan assets (1,166) (797) (1,268) Net amortization and deferral 709 318 742 - ------------------------------------------------------------------- Net postretirement cost $3,640 $3,146 $4,106 ===================================================================
Of the above net postretirement costs recorded, $2.7 million in 1997, $2.3 million in 1996, and $3.1 million in 1995 were charged to operating expenses, and the remainder was recorded in construction and other accounts.
Work Force Reduction Programs
The Company recorded costs related to work force reductions programs of $1.4 million in 1997, $1.2 million in 1996, and $7 million in 1995. The Company has also incurred its pro rata share for the costs of affiliated companies' programs. The costs related to these programs were $1.3 million for 1997, $2.1 million for 1996, and $1 million for 1995. The costs related to work force reductions have been expensed to operation expenses.
3. LITIGATION AND REGULATORY MATTERS
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the reasonableness of the operating companies' wholesale rate schedules and contracts that have a return on common equity of 13.75 percent or greater. The contracts that could be affected by the hearings include substantially all of the transmission, unit power, long-term power and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that changes in rate schedules and contracts were not necessary and that the FERC staff failed to show how any changes were in the public interest. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on substantially the same issues as in the 1991 proceeding. In November 1995, a FERC administrative law judge issued an opinion that the FERC staff failed to meet its burden of proof, and therefore, no change in the equity return was necessary. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were applied to all of the schedules and contracts involved in both proceedings, as well as certain other contracts that reference these proceedings in determining return on common equity, and if refunds were ordered, the amount of refunds could range up to approximately $194 million for Southern Company, including approximately $13 million for the Company at December 31, 1997. Although management believes that rates are not excessive and that refunds are not justified, the final outcome of this matter cannot now be determined.
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. Beginning with this initial period through September 1996, recovery under the ECRC was determined semi-annually. In August 1996, the FPSC approved annual recovery periods beginning with the October 1996 through September 1997 period. Recovery includes a true-up of the prior period and a projection of the ensuing period. During 1997 and 1996, the Company recorded ECRC revenues of $10.2 million and $11.0 million, respectively.
At December 31, 1997, the Company's liability for the estimated costs of environmental remediation projects for known sites was $7.3 million. These estimated costs are expected to be expended during the period 1998 to 2002.
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These projects have been approved by the FPSC for recovery through the ECRC discussed above. Therefore, the Company recorded $1.7 million in current assets and current liabilities, and $5.6 million in deferred assets and liabilities representing the future recoverability of these costs.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $68 million in 1998, $62 million in 1999, and $62 million in 2000. 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, 1997, significant purchase commitments were outstanding in connection with the construction program. The Company does not have any major generating plants under construction, however, significant construction will continue 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 primarily from internal sources. Requirements not met from internal sources will be derived from the sale of additional first mortgage bonds, long-term unsecured debt, pollution control bonds, and preferred securities; bank notes; and capital contributions from Southern Company. In addition, the Company may issue additional long-term debt and preferred securities primarily for debt maturities and redemptions of higher-cost securities.
Bank Credit Arrangements
At December 31, 1997, the Company had $41.5 million of lines of credit with banks subject to renewal June 1 of each year, of which $32.5 million remained unused. In addition, the Company has two unused committed lines of credit totaling $61.9 million that were established for liquidity support of its variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees and/or to maintain compensating balances with the banks. The compensating balances, which represent substantially all of the cash of the Company except for daily working funds and like items, are not legally restricted from withdrawal. In addition, the Company has bid-loan facilities with ten major money center banks that total $180 million, of which $38 million was committed at December 31, 1997.
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, 1997, were as follows:
Year Fuel ------- ---------------- (in millions) 1998 $82 1999 77 2000 70 2001 72 2002 74 2003 - 2007 408 -------------------------------------------------------- Total commitments $783 =========================================================
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 amount is being amortized to expense on a per ton
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basis over a ten-year period. The remaining unamortized amount was $2.7 million at December 31, 1997.
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 amount is being amortized to expense on a per ton basis through the first quarter of 1998. The remaining unamortized amount was $1.8 million at December 31, 1997.
The amortization expense of these contract buyouts and renegotiations is being 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. The Company has the option after three years from the date of the original contract on the second lease agreement to purchase the railcars at the greater of the termination value or the fair market value. Additionally, 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 $2.3 million in 1997 and $1.7 million in 1996. The annual amounts for 1998 through 2002 will be $2.8 million, $2.8 million, $2.1 million, $1.7 million, and $1.7 million respectively, and after 2002 will total $17.8 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.
At December 31, 1997, 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 $185,723(1) $222,230 Accumulated Depreciation $58,219 $108,176 Construction Work in Progress $282 $231
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, revenues from capacity sales primarily affect profitability. The capacity
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revenues from these sales were $24.9 million in 1997, $25.4 million in 1996, and $25.9 million in 1995.
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, 211 megawatts of net dependable capacity were sold by the Company during 1997, and sales will remain at that level until the expiration of the contracts in 2010, unless reduced by FPC, FP&L and JEA after 2000.
Capacity and energy sales to FP&L, the Company's largest single customer, provided revenues of $25.4 million in 1997, $27.2 million in 1996, and $25.4 million in 1995, or 4.1 percent, 4.3 percent, and 4.1 percent of operating revenues, respectively.
8. INCOME TAXES
At December 31, 1997, the tax-related regulatory assets to be recovered from customers were $26.6 million. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. At December 31, 1997, the tax-related regulatory liabilities to be credited to customers were $56.9 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:
1997 1996 1995 ---------------------------------- (in thousands) Total provision for income taxes: Federal-- Currently payable $34,522 $31,022 $29,018 Deferred --current year 19,297 26,072 23,172 --reversal of prior years (25,778) (24,780) (23,116) - ------------------------------------------------------------------ 28,041 32,314 29,074 - ------------------------------------------------------------------ State-- Currently payable 5,975 4,394 4,778 Deferred --current year 2,868 3,904 3,313 --reversal of prior years (3,434) (3,039) (2,979) - ------------------------------------------------------------------ 5,409 5,259 5,112 - ------------------------------------------------------------------ Total 33,450 37,573 34,186 Less income taxes charged (credited) to other income (1,584) (248) 121 - ------------------------------------------------------------------ Total income taxes charged to operations $35,034 $37,821 $34,065 ==================================================================
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:
1997 1996 ----------- ----------- (in thousands) Deferred tax liabilities: Accelerated depreciation $156,328 $151,664 Property basis differences 19,220 21,028 Other 14,242 17,622 - ------------------------------------------------------------------- Total 189,790 190,314 - ------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 9,268 9,773 Postretirement benefits 6,976 5,767 Other 10,861 7,814 - ------------------------------------------------------------------- Total 27,105 23,354 - ------------------------------------------------------------------- Net deferred tax liabilities 162,685 166,960 Less current portion, net (3,617) 3,103 - ------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $166,302 $163,857 ===================================================================
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation and amortization in the Statements of Income. Credits amortized in
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this manner amounted to $2.2 million in 1997 and $2.3 million in 1996 and 1995. At December 31, 1997, 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:
1997 1996 1995 --------- --------- --------- 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 (1) (1) (3) Other, net (4) (2) (2) - --------------------------------------------------------------- Effective income tax rate 35% 37% 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. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
9. COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES
In January 1997, Gulf Power Capital Trust I (Trust I), of which the Company owns all of the common securities, issued $40 million of 7.625 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust I are $41 million aggregate principal amount of the Company's 7.625 percent junior subordinated notes due December 31, 2036.
In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company also 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 Gulf Power Capital Trust I and Trust II.
Gulf Power Capital Trust I and Trust II are subsidiaries of the Company, and accordingly are consolidated in the Company's financial statements.
10. POLLUTION CONTROL OBLIGATIONS AND OTHER LONG-TERM DEBT
Details of pollution control obligations and other long-term debt at December 31 are as follows:
1997 1996 -------------------------- (in thousands) Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: Collateralized 5.25% due 2006 $12,075 $12,075 8.25% due 2017 - 32,000 6.75% due 2022 - 8,930 Variable Rate due 2022 Remarketable daily 40,930 - 5.70% due 2023 7,875 7,875 5.80% due 2023 32,550 32,550 6.20% due 2023 13,000 13,000 6.30% due 2024 22,000 22,000 Variable Rate due 2024 Remarketable daily 20,000 20,000 5.50% due 2026 21,200 21,200 - --------------------------------------------------------------- $169,630 $169,630 - --------------------------------------------------------------- Other long-term debt: 5.2125% due 1996-1998 5,754 16,823 6.44% due 1994-1998 2,573 7,476 Variable Rate due 1999 13,500 13,500 Variable Rate due 1999 13,500 13,500 7.5% Junior Subordinated Note due 2037 20,000 - - --------------------------------------------------------------- 55,327 51,299 - --------------------------------------------------------------- Total $224,957 $220,929 ===============================================================
Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds. With respect to the collateralized pollution control revenue
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NOTES (continued) Gulf Power Company 1997 Annual Report
bonds, the Company has executed and delivered to trustees a like principal amount of first mortgage bonds, or in the case of the $40.9 million issue a deed of trust, as security for obligations under collateralized installment agreements. The principal and interest on the first mortgage bonds will be payable only in the event of default under the agreements.
The estimated annual maturities of other long-term debt are as follows: $8.3 million in 1998 and $27 million in 1999.
11. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirement and scheduled maturities and redemptions of long-term debt and preferred stock due within one year at December 31 is as follows:
1997 1996 ---------------------- (in thousands) Bond improvement fund requirement $ 1,300 $ 1,550 Less: Portion to be satisfied by certifying property additions 1,300 1,550 - --------------------------------------------------------------- Cash sinking fund requirement - - Maturities of first mortgage bonds 45,000 25,000 Current portion of other long-term debt (Note 10) 8,327 15,972 Redemption of preferred stock - 24,500 - --------------------------------------------------------------- Total $53,327 $65,472 ===============================================================
The first mortgage bond improvement (sinking) 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 obligations. The requirement may be satisfied by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 and 2/3 times the requirement.
12. 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, 1997, retained earnings of $127 million were restricted against the payment of cash dividends on common stock under the terms of the mortgage indenture.
The Company's charter previously limited cash dividends on common stock to 50 percent of net income available for such stock during a prior period of 12 months if the capitalization ratio is below 20 percent and to 75 percent of such net income if such ratio is 20 percent or more but less than 25 percent. The capitalization ratio is defined as the ratio of common stock equity to total capitalization, including retained earnings, adjusted to reflect the payment of the proposed dividend. At December 31, 1997, the ratio was 50.4 percent. These restrictions were removed by a vote of preferred shareholders on December 10, 1997.
13. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1997 and 1996 are as follows:
Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock - ------------------------------------------------------------------ (in thousands) March 31, 1997 $141,374 $20,212 $10,740 June 30, 1997 145,292 19,153 10,386 Sept. 30, 1997 193,710 34,750 27,484 Dec. 31, 1997 145,480 15,068 9,000
March 31, 1996 $154,921 $20,201 $11,258 June 30, 1996 153,821 21,565 12,581 Sept. 30, 1996 179,619 32,568 23,721 Dec. 31, 1996 146,004 19,458 10,285 - ------------------------------------------------------------------
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 1997 Annual Report
The management of Mississippi Power Company has prepared--and is responsible for--the financial statements and related information included in this report. These statements were prepared in accordance with generally accepted accounting principles appropriate in the circumstances and necessarily include amounts that are based on best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that books and records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based upon a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting control maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an ongoing basis by the internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of four directors who are not employees, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Mississippi Power Company in conformity with generally accepted accounting principles.
/s/ Dwight H. Evans Dwight H. Evans President and Chief Executive Officer
/s/ Michael W. Southern Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer
February 11, 1998
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of 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, 1997 and 1996, and the related statements of income, retained earnings, paid-in capital, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-196 through II-211) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Atlanta, Georgia February 11, 1998
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 1997 Annual Report RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's net income after dividends on preferred stock for 1997 was $54.0 million, reflecting a 2.4 percent or $1.3 million increase above 1996. The increased earnings is due to lower operating expenses.
In 1996, earnings were $52.7 million, up $0.2 million from the prior year. Earnings reflected a modest increase in energy sales, an annual retail rate decrease of $3.0 million under the Environmental Compliance Overview Plan (ECO Plan) and an annual retail increase of $4.5 million under the Performance Evaluation Plan (PEP) which became effective in October 1996.
Revenues
The following table summarizes the factors impacting operating revenues for the past three years:
Increase (Decrease) from Prior Year ------------------------------------- 1997 1996 1995 ------------------------------------- (in thousands) Retail -- Change in base rates (PEP and ECO Plan) $ 3,177 $ (402) $ 2,694 Sales growth 109 11,187 4,045 Weather (1,118) (5,585) 4,513 Fuel cost recovery and other 948 (1,255) 3,806 --------------------------------------------------------------- Total retail 3,116 3,945 15,058 --------------------------------------------------------------- Sales for resale -- Non-affiliates 5,464 7,776 3,698 Affiliates (11,606) 14,139 (1,847) --------------------------------------------------------------- Total sales for resale (6,142) 21,915 1,851 Other operating revenues 2,585 1,616 482 --------------------------------------------------------------- Total operating revenues $ (441) $27,476 $17,391 =============================================================== Percent change (0.1)% 5.3% 3.5% ---------------------------------------------------------------
Retail revenues in 1997 were $417 million, up 0.8 percent from the corresponding amount in 1996. The increase in retail revenues was primarily caused by the October 1996 PEP retail rate increase, as mentioned above, and the January 1997 ECO Plan retail rate increase of $0.9 million. Retail revenues for 1996 when compared to 1995 reflected a 1.0 percent increase due to modest growth in energy sales to industrial, commercial and residential customers, as well as changes in retail revenues due to the ECO Plan and PEP. Changes in base rates reflect any rate changes made under the PEP and ECO Plan.
Under the fuel cost recovery provision, recorded fuel revenues are equal to recorded fuel expenses, including the fuel component and the operation and maintenance component of purchased energy. 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 -- oil and natural gas.
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 3.6 percent in 1997 and 6.4 percent in 1996, with the related revenues rising 1.6 percent and 7.1 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to Mississippi Power's.
Sales for resale to non-territorial utilities are primarily under long-term contracts consisting 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. Under these long-term contracts, the capacity and energy components were:
1997 1996 1995 ------------------------------------- (in thousands) Capacity $ 8 $ - $ 268 Energy 1,896 3,761 3,627 ---------------------------------------------------------- Total $1,904 $3,761 $3,895 ==========================================================
Capacity revenues for Mississippi Power varied due to changes in the contracts and in the allocation of transmission capacity revenues throughout the Southern electric system. Most of the Company's capacity revenues are derived from transmission charges.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1997 Annual Report
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 1997 and the percent change for the last three years:
Amount Percent Change (millions of ----------- ------------------------------ kilowatt-hours) 1997 1997 1996 1995 ---------- ------------------------------ Residential 2,039 (2.0)% 1.9% 6.2% Commercial 2,408 4.0 3.3 6.7 Industrial 3,982 0.6 3.8 (0.9) Other 40 2.6 1.9 1.1 ---------- Total retail 8,469 0.9 3.2 2.9 Sales for resale -- Non-affiliates 2,895 6.2 9.4 (2.4) Affiliates 479 (31.0) 184.7 39.7 ---------- Total 11,843 0.2 8.7 2.2 ================================================================
Total retail energy sales for 1997 compared to 1996 and for 1996 compared to 1995 increased primarily due to growth in the number of customers served by the Company.
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 which 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 for 1997 were $466 million, reflecting a decrease of $1.3 million or 0.3 percent when compared to the corresponding amount in 1996. The decrease was due primarily to lower administrative and general expenses. In 1996, total operating expenses increased by 6.6 percent when compared to the prior year due to higher fuel expenses, higher maintenance and higher depreciation and amortization.
Fuel costs are the single largest expense for the Company. Fuel expenses for 1997 when compared to 1996 increased by 0.4 percent due to a 1.1 percent increase in generation. The increase in generation was due to the higher demand for energy in the retail sector. In 1997, expenses related to purchased power from non-affiliates decreased 19.1 percent and expenses related to purchased power from affiliates increased 13.7 percent due to the increased availability of energy within the Southern electric system.
A comparison of 1996 to 1995 fuel costs reflects an increase that was due to a 21.7 percent increase in generation. This increased generation was due to higher demand for energy across the Southern electric system. Further, the higher demand for energy resulted in higher purchased power costs from non-affiliates and lower purchased power from affiliates of the Southern electric system.
Purchased power consists mainly of energy purchases from affiliates in the Southern electric system. Purchased power transactions (both 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1997 Annual Report
The amount and sources of energy supply, the average cost of fuel per net kilowatt-hour generated, and the total average cost of energy supply (including purchased power) were as follows:
1997 1996 1995 ------------------------------ Total generation (millions of kilowatt-hours) 10,289 10,180 8,368 Sources of energy supply (percent) -- Coal 70 70 58 Gas 13 12 15 Oil * * * Purchased Power 17 18 27 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.44 1.43 1.58 Gas 3.54 4.24 2.32 Oil - 5.71 6.21 Total average cost of energy supply 1.57 1.56 1.53 - -------------------------------------------------------------- * Not meaningful because of minimal generation from the fuel source.
Other operation expense in 1997 decreased 3.5 percent from the amount recorded in 1996. The decrease was due to lower administrative and general expenses.
Maintenance expenses in 1996 when compared to 1995 increased due to the timing of maintenance performed at Plants Daniel and Watson, as well as other projects.
In 1996, as compared to 1995, depreciation and amortization increased primarily due to additional plant investment, higher depreciation rates beginning in 1996, and increased amortization of regulatory assets.
Comparisons of taxes other than income taxes for 1997 to 1996 and for 1996 to 1995 show increases of 1.1 percent and 2.6 percent, respectively, due to higher municipal franchise taxes resulting from higher retail revenues.
Effects of Inflation
Mississippi Power is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in long-lived utility plant. Conventional accounting for historical costs does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors ranging from regulatory matters to energy sales growth to a less regulated more competitive environment. Expenses are subject to constant review and cost control programs. See Note 2 to the financial statements under "Workforce Reduction Programs" for information regarding the Company's workforce reduction plan of 1997.
The Company currently operates as a vertically integrated company providing electricity to customers within its traditional service area located in southeastern Mississippi. Prices for electricity provided by the Company to retail customers are set by the MPSC under cost-based regulatory principles.
Mississippi Power is also maximizing the utility of invested capital and minimizing the need for capital by refinancing, decreasing the average fuel stockpile, raising generating plant availability and efficiency, and aggressively controlling the construction budget.
Operating revenues will be affected by any changes in rates under the PEP, the Company's performance based ratemaking plan, and the ECO Plan. PEP has proven to be a stabilizing force on electric rates, with only moderate changes in rates taking place. The ECO Plan provides for recovery of costs (including costs of capital) associated with environmental projects approved by the Mississippi Public Service Commission (MPSC), most of which are required to comply with Clean Air Act Amendments of 1990 (Clean Air Act) regulations. The ECO Plan is operated independently of PEP. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1997 Annual Report
The Federal Energy Regulatory Commission (FERC) regulates the Company's wholesale rate schedules, power sales contracts and transmission facilities. The FERC is currently reviewing the rate of return on common equity included in these schedules and contracts and may require such returns to be lowered, possibly retroactively.
Further discussion of PEP, the ECO Plan, and proceedings before the FERC is found in Note 3 to the financial statements herein.
Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in Mississippi Power's service area.
The electric utility industry in the United States is currently undergoing a period of dramatic change as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows Independent Power Producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. The Company is aggressively working to maintain and expand its share of wholesale sales in the Southeastern power markets.
Although the Energy Act does not permit retail transmission access, it has been a catalyst for some emerging restructuring and consolidation within the utility industry. There are federal and various state initiatives in various stages which would promote wholesale and retail competition. Certain of these initiatives would result in some form of separation of generation, transmission and distribution facilities. As these changes take place the structure of the utility industry could change. Restructuring initiatives are being discussed in Mississippi; none have been enacted to date. Enactment would have to encompass the resolution of numerous complex legislative, jurisdictional, financial and operational issues.
Mississippi Power is subject to the provisions of Financial Accounting Standards Board 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 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 heavily dependent upon complex computer systems for all phases of its operations. The year 2000 issue--common to most corporations--concerns the inability of certain software and databases to properly recognize date sensitive information related to the year 2000 and thereafter. This problem could result in a material disruption to the company's operations, if not corrected. Mississippi Power has assessed and developed a detailed strategy to prevent or at least minimize problems related to the year 2000 issue. In 1997, resources were committed and implementation began to modify the affected information systems. Total costs related to the project are estimated to be approximately $4.8 million, of which $0.5 million was spent in 1997. Most all remaining costs will be expensed in 1998. Implementation is currently on schedule. Although, the degree of success of this project cannot be determined at this time, management believes that there will be no significant effect on the Company's operations.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1997 Annual Report
Exposure to Market Risk
Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1997, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which will be effective in 1998. This statement establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. The objective of the statement is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners (comprehensive income). Comprehensive income is the total of net income and all other non-owner changes in equity. The Company will adopt the new rules in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an Enterprise and Related Information. Southern Company adopted the new rules effective December 31, 1997. This statement requires that a public business enterprise report financial and descriptive information about its reportable operating segments. This statement also establishes standards for related disclosures about products and services, geographic areas, and major customers. Mississippi Power adopted the new rules in 1997, and they did not have any significant impact on the Company's financial reporting. However, this conclusion may change as industry restructuring and competitive factors influence the Company's operations.
FINANCIAL CONDITION
Overview
The principal change in Mississippi Power's financial condition during 1997 was gross property additions to utility plant of $55 million. Funding for gross property additions and other capital requirements has been provided from operating activities, principally earnings and the non-cash charges to income of depreciation and amortization, and the issuance of preferred securities. The Statements of Cash Flows provide additional details.
Financing Activity
Retirements, including maturities during 1997, primarily related to preferred stock, totaled some $42 million. 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. (See the Statements of Cash Flows for further details.) Composite financing rates for the years 1995 through 1997 as of year-end were as follows:
1997 1996 1995 ----------------------------- Composite interest rate on long-term debt 6.16% 6.03% 6.63%
Composite preferred stock dividend rate 6.33% 6.58% 6.58%
Composite interest rate on preferred securities 7.75% - - -----------------------------------------------------------
The decrease in the composite dividend rate on preferred stock in 1997 is primarily the result of retirements.
Capital Structure
At year-end 1997, the Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, was 52.0 percent, compared to 48.9 percent in 1996. The increase in equity ratio in 1997 is attributed to the reclassification of $35 million of long-term debt to a current liability.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $450 million ($67 million in 1998, $92 million in 1999, and $291 million in 2000). The major emphasis within the construction program will be on the upgrade of existing facilities and the addition of combined cycle generation. In 1998, Mississippi Power received approval from the MPSC to build up to 1,000 megawatts of natural gas-fired combined cycle generation at Plant Daniel. Construction is expected to begin in 1999.
Revisions may be necessary because of factors such as changes in business conditions, revised load projections, the availability and cost of capital, and changes in environmental regulations, and alternatives such as leasing.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1997 Annual Report
Other Capital Requirements
In addition to the funds required for the Company's construction program, approximately $155.1 million will be required by the end of 2000 for present sinking fund requirements and maturities of long-term debt. Mississippi Power plans to continue, when economically feasible, to retire higher cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected Mississippi Power and the other operating companies of Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants are required in two phases. Phase I compliance began in 1995 and initially affected 28 generating plants in the Southern electric system. As a result of Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required in 2000, and all fossil-fired generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Phase I compliance totaled approximately $65 million for Mississippi Power.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. The full impact of Phase II compliance cannot now be determined with certainty, pending the continuing development of a market for emission allowances, the completion of EPA regulations, and the possibility of new emission reduction technologies.
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 Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. Also, in October 1997, the EPA issued a proposed regional ozone rule which-- if implemented-- could require substantial further reductions in NOx emissions from fossil-fueled generating facilities. Implementation of the standards and the proposed rule could result in significant additional compliance costs and capital expenditures that cannot be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant emissions; and hazardous waste disposal requirements. The impact of new standards will depend on the development and implementation of applicable regulations.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur costs to clean up properties currently or previously owned. Upon identifying potential sites, the Company conducts studies, when possible, to determine the extent of any required cleanup costs. Should remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. A currently owned site where manufactured gas plant operations were located prior to the Company's ownership is being investigated for potential remediation. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1997 Annual Report
Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect the Company. The impact of new legislation -- if any - -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for lawsuits alleging damages caused by electromagnetic fields. The likelihood or outcome of such potential lawsuits cannot be determined at this time.
Sources of Capital
At December 31, 1997, the Company had $76.3 million of unused committed credit agreements. The Company had no short-term notes payable outstanding at year end 1997.
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 stock, in addition to pollution control revenue bonds issued for the Company's benefit by public authorities. Recently, the Company issued trust preferred securities and plans to issue unsecured debt in 1998. In this regard, Mississippi Power sought and obtained stockholder approval in 1997 to amend its corporate charter eliminating restrictions on the amounts of unsecured indebtedness the Company may incur.
Mississippi Power is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's coverage ratios are sufficiently high enough to permit, at present interest rate levels, any foreseeable security sales. The amount of securities which the Company will be 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 statements in addition to 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 statements; 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 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, Southern Company Services (SCS), Southern Communications Services (Southern Communications), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), and Southern Energy Solutions, and other direct and indirect subsidiaries. The operating companies (Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company) provide electric service in four southeastern states. Contracts among the companies--dealing with jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. SCS provides, at cost, specialized services to Southern Company and to the subsidiary companies. Southern Communications provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Energy Solutions develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. Mississippi Power is also subject to regulation by the FERC and the Mississippi Public Service Commission (MPSC). The Company follows generally accepted accounting principles and complies with the accounting policies and practices prescribed by the respective commissions. The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates and the actual results may differ from those estimates.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
Mississippi Power is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets as of December 31 relate to:
1997 1996 ------------------------- (in thousands) Deferred income taxes $21,906 $22,274 Vacation pay 5,030 4,806 Workforce reduction costs - 1,991 Workforce reduction plan of 1997 18,236 - Premium on reacquired debt 9,508 10,672 Deferred environmental costs 1,583 1,679 Property damage reserve (13,991) (12,955) Deferred income tax credits (38,203) (40,568) Other, net (2,982) (2,882) - ---------------------------------------------------------------- Total $ 1,087 $(14,983) ================================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off the net regulatory assets and liabilities related to that portion of operations that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine any impairment to other assets, including plant, and, write down the assets, if impaired, to their fair value.
Revenues
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, the energy component of purchased power costs and certain other costs. Retail rates also include
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NOTES (continued) Mississippi Power Company 1997 Annual Report
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. In 1997, uncollectible accounts continued to average less than 1 percent of revenues.
Depreciation
Depreciation of the original cost of depreciable utility plant in service is provided by using composite straight-line rates which approximated 3.3 percent in 1997 and 1996, and 3.2 percent in 1995. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost - -- together with the cost of removal, less salvage -- is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of facilities.
Income Taxes
Mississippi Power uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Utility Plant
Utility plant is stated at original cost. This cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. If applicable, the cost of maintenance, repairs, and replacement of minor items of property are charged to maintenance expense except for the maintenance of coal cars and a portion of the railway track maintenance, which are charged to fuel stock. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Value of Financial Instruments, all financial instruments of the Company for which the carrying amount does not approximate fair value, at December 31 are as follows: Carrying Fair Amount Value -------------------- (in millions) Long-term debt: At December 31, 1997 $327 $330 At December 31, 1996 326 324 Preferred securities: At December 31, 1997 35 36 At December 31, 1996 - - - --------------------------------------------------------
The fair value for long-term debt and preferred securities was based on either closing market price or closing price of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when used or installed.
Provision for Property Damage
Mississippi Power is self-insured for the cost of storm, fire and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by regulatory authorities, the Company provided for such costs by charges to income of $1.5 million in each of the years 1997, 1996 and 1995. The cost of repairing damage resulting from such events that individually exceed $50 thousand is charged to the accumulated provision to the extent it is available. Effective January 1995, regulatory treatment by the MPSC allowed a maximum accumulated provision of $18 million. As of December 31, 1997, the accumulated provision amounted to $14.0 million.
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NOTES (continued) Mississippi Power Company 1997 Annual Report
2. RETIREMENT BENEFITS
Pension Plan
Mississippi Power has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. Benefits are based on one of the following formulas: years of service and final average pay or years of service and a flat-dollar benefit. The Company uses the "entry age normal method with a frozen initial liability" actuarial method for funding purposes, subject to limitations under federal income tax regulations. Amounts funded to the pension trust are primarily invested in equity and fixed-income securities. FASB Statement No. 87, Employers' Accounting for Pensions, requires use of the "projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
Mississippi Power also provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations or to the extent required by the Company's regulatory commissions. Amounts funded are primarily invested in debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, requires that medical care and life insurance benefits for retired employees be accounted for on an accrual basis using a specified actuarial method, "benefit/years-of-service." The cost of postretirement benefits is reflected in rates on a current basis.
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the Balance Sheets at December 31 are as follows:
Pension ------------------------ 1997 1996 ------------------------ (in thousands) Actuarial present value of benefit obligation: Vested benefits $102,764 $92,091 Non-vested benefits 3,120 5,191 -------------------------------------------------------------- Accumulated benefit obligation 105,884 97,282 Additional amounts related to projected salary increases 26,247 30,552 -------------------------------------------------------------- Projected benefit obligation 132,131 127,834 Less: Fair value of plan assets 207,457 179,658 Unrecognized net gain (78,936) (56,674) Unrecognized prior service cost 5,819 6,422 Unrecognized transition asset (4,904) (5,449) -------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 2,695 $3,877 ==============================================================
Postretirement Benefits ------------------------ 1997 1996 ------------------------ (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $19,816 $20,841 Employees eligible to retire 3,691 2,703 Other employees 19,910 17,564 ------------------------------------------------------------ Accumulated benefit obligation 43,417 41,108 Less: Fair value of plan assets 12,916 10,210 Unrecognized net (gain)/ loss (1,980) 1,136 Unrecognized transition obligation 5,314 5,911 ------------------------------------------------------------ Accrued liability recognized in the Balance Sheets $27,167 $23,851 ============================================================
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The weighted average rates assumed in the above actuarial calculations were:
1997 1996 1995 --------------------------------- Discount 7.5% 7.8% 7.3% Annual salary increase 5.0 5.3 4.8 Long-term return on plan assets 8.5 8.5 8.5 ------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.8 percent for 1997, decreasing gradually to 5.5 percent through the year 2005 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated benefit obligation as of December 31, 1997, by $3.3 million and the aggregate of the service and interest cost components of the net retiree cost by $0.3 million.
Components of the plans' net cost are shown below:
Pension -------------------------------- 1997 1996 1995 -------------------------------- (in thousands) Benefits earned during the year $4,015 $ 3,842 $ 3,636 Interest cost on projected benefit obligation 9,408 9,310 8,434 Actual (return) loss on plan assets (30,680) (20,438) (32,232) Net amortization and deferral 16,026 6,442 18,650 -------------------------------------------------------------- Net pension income $(1,231) $ (844) $ (1,512) ==============================================================
Of the above net pension income, $(0.9) million in 1997, $(0.6) million in 1996, and $(1.1) million in 1995 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits ------------------------------ 1997 1996 1995 ------------------------------ (in thousands) Benefits earned during the year $ 867 $ 958 $1,525 Interest cost on accumulated benefit obligation 2,922 2,830 3,442 Amortization of transition obligation over 20 years 362 362 1,027 Actual (return) loss on plan assets (1,388) (990) (1,436) Net amortization and deferral 566 312 851 ================================================================ Net postretirement costs $3,329 $3,472 $5,409 ================================================================
Of the above net postretirement costs recorded, $2.6 million in 1997, $2.8 million in 1996, and $3.9 million in 1995 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Workforce Reduction Programs
During 1994, Mississippi Power and SCS instituted workforce reduction programs. The costs of the SCS workforce reduction program were apportioned among the various entities that form the Southern electric system, with the Company's portion amounting to $1.4 million. The Company instituted an early retirement incentive program in April 1994 and deferred the related costs of approximately $12.9 million. The Company received authority from the MPSC to defer these costs, as well as its portion of the costs of the SCS program, and to amortize over a period not to exceed 60 months, beginning no later than January 1995. The Company expensed $2.0 million, $5.3 million, and $4.0 million of the cost of these programs in 1997, 1996 and 1995, respectively. In 1997, Mississippi Power expensed its pro-rata share of the costs for affiliated companies' programs of $0.5 million.
In 1997, approximately one hundred employees of Mississippi Power, in certain areas, including finance, environmental quality and external affairs, accepted the terms under a workforce reduction plan. The total cost to be incurred in connection with this voluntary plan is expected to be $18.2 million. The MPSC approved the deferral and amortization of these program costs over a period not to exceed 60 months beginning no later than July 1998. The unamortized balance of this program was $18.2 million at December 31, 1997.
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NOTES (continued) Mississippi Power Company 1997 Annual Report
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Plans
Mississippi Power's retail base rates are set under a Performance Evaluation Plan (PEP) approved by the MPSC in 1994. PEP was designed with the objective that the plan would reduce the impact of rate changes on the customer and provide incentives for Mississippi Power to keep customer prices low. PEP includes a mechanism for sharing rate adjustments based on the Company's ability to maintain low rates for customers and on the Company's performance as measured by three indicators that emphasize price and service to the customer. PEP provides for semiannual evaluations of Mississippi's performance-based return on investment. Any change in rates is limited to 2 percent of retail revenues per evaluation period. PEP will remain in effect until the MPSC modifies or terminates the plan. In September 1996, the MPSC under PEP approved a retail revenue increase of $4.5 million (1.06 percent of annual retail revenue) which became effective in October 1996. There were no PEP retail revenue changes for 1997.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the reasonableness of the operating companies' wholesale rate schedules and contracts that have a return on equity of 13.75 percent or greater. The contracts that could be affected by the hearings include substantially all of the transmission, unit power, long-term power and other similar contracts, including the Company's transmission facilities agreement discussed in Note 5 under "Lease Agreements."
In August 1992, a FERC administrative law judge issued an opinion that changes in rate schedules and contracts were not necessary and that the FERC staff failed to show how any changes were in the public interest. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on substantially the same issues as in the 1991 proceeding. In November 1995, a FERC administrative law judge issued an opinion that the FERC staff failed to meet its burden of proof, and therefore, no change in the equity return was necessary. The FERC staff has filed exceptions to the administrative law judge's opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were applied to all of the schedules and contracts involved in both proceedings -- as well as certain other contracts that reference these proceedings in determining return on common equity -- and if refunds were ordered, the amount of refunds could range up to approximately $4.1 million for Mississippi Power at December 31, 1997. Although management believes that rates are not excessive and that refunds are not justified, the final outcome of this matter cannot now be determined.
Environmental Compliance Overview Plan
The MPSC approved Mississippi Power's ECO Plan in 1992. The plan establishes procedures to facilitate the MPSC's overview of the Company's environmental strategy and provides for recovery of costs (including costs of capital) associated with environmental projects approved by the MPSC. Under the ECO Plan any increase in the annual revenue requirement is limited to 2 percent of retail revenues. However, the plan also provides for carryover of any amount over the 2 percent limit into the next year's revenue requirement. The ECO Plan had previously resulted in an annual retail rate increase of $3.7 million, effective in May 1995 which included $1.6 million of 1994 carryover and an annual retail rate increase of $7.6 million, effective in April 1994. The Company's 1996 annual filing under the ECO Plan resulted in a $3.0 million decrease in retail rates, effective in April 1996. In 1997, the Company's filing with the MPSC under the ECO Plan resulted in an annual retail rate increase of $0.9 million. The 1998 ECO filing, if approved by the MPSC, 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 remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. A currently owned site where manufactured gas plant operations were located prior to the Company's ownership is being investigated for potential remediation. The remedial investigation is near completion and is being conducted in conjunction with the Mississippi Department of Environmental Quality. In recognition of probable further study and remediation, the Company in 1995 recorded a liability and a deferred debit (regulatory asset) of $1.8 million, including feasibility study costs. The Company recognizes such costs as they are incurred and recovers them under the
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NOTES (continued) Mississippi Power Company 1997 Annual Report
ECO Plan as provided in the Company's 1995 ECO order. As of December 31, 1997, the balance in the liability and regulatory asset accounts was $1.6 million. If this site were required to be remediated, industry studies show the Company could incur cleanup costs ranging from $1.5 million to $10 million before giving consideration to possible recovery of clean-up costs from other parties.
4. CONSTRUCTION PROGRAM
Mississippi Power is engaged in continuous construction programs, the costs of which are currently estimated to total $67 million in 1998, $92 million in 1999, and $291 million in 2000.
The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; revised load growth estimates; changes in environmental regulations; increasing costs of labor, equipment and materials; and cost of capital. Significant construction will continue related to transmission and distribution facilities, the upgrading of generating plants, and the addition of combined cycle generation.
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 stock and the receipt of capital contributions from Southern Company.
The amounts of first mortgage bonds and preferred stock which can be issued in the future will be contingent upon market conditions, adequate earnings levels, regulatory authorizations and other factors.
At December 31, 1997, Mississippi Power had total committed credit agreements with banks for $96.3 million. At year-end 1997, the unused portion of these committed credit agreements was $76.3 million. These credit agreements expire at various dates in 1998 and in 2000. Some of these agreements allow short-term borrowings to be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first 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, 1997, the Company had no 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 the Company's fixed property and franchises.
Lease Agreements
In 1984, Mississippi Power and Gulf States Utilities Company (Gulf States) entered into a forty-year transmission facilities agreement whereby Gulf States 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 1997 use fees collected under this agreement, net of related expenses, amounted to $3.5 million each year, and are included within Other Income in the Statements of Income.
In 1989, Mississippi Power entered into a twenty-two year lease agreement for the use of 495 aluminum railcars. In 1994, a second lease agreement for the use of 250 additional aluminum railcars was also entered into for twenty-two years. The Company has the option to purchase the 745 railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. In 1997, a third lease agreement for the use of 360 railcars was also entered into for three years, with a monthly renewal option for up to an additional nine months. All of these leases, totaling 1,105 railcars, were for the transport of coal at Plant Daniel.
Gulf Power, as joint owner of Plant Daniel, is responsible for one half of the lease cost. The Company's share (50%) of the leases, charged to fuel inventory, was $2.0 million in 1997, and $1.7 million in both 1996 and 1995. The Company's annual lease payments for 1998 through 2002 will average approximately $2.2 million and after 2002, lease payments total in aggregate approximately $18 million.
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NOTES (continued) Mississippi Power Company 1997 Annual Report
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, 1997 were as follows:
Year Fuel (in millions) 1998 $137 1999 88 - --------------------------------------------------- Total commitments $225 ===================================================
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; 350 megawatts in 1999; and 400 megawatts in 2000. In 1997, Mississippi Power exercised its option to purchase 250 megawatts of peaking capacity. In June 1997, the MPSC approved Mississippi Power's request that it be allowed to earn a return on the capacity portion of this agreement. Mississippi Power expects to exercise its options to purchase 300 megawatts of summer peaking capacity in 1998.
6. JOINT OWNERSHIP AGREEMENTS
Mississippi Power and Alabama Power own as tenants in common Units 1 and 2 at Greene County Electric Generating Plant (coal) located in Alabama; and Mississippi Power and Gulf Power own as tenants in common Daniel Electric Generating Plant (coal) located in Mississippi. At December 31, 1997, 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% $ 63,206 $30,168
Daniel 1,000 50% 220,984 92,484 ----------------------------------------------------------------
Mississippi Power's share of plant operating expenses is included in the corresponding operating expenses in the Statements of Income.
7. LONG-TERM POWER SALES AGREEMENTS
Mississippi Power and the other operating affiliates of Southern Company have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The capacity revenues have been $8,000 in 1997; $0 in 1996; and $268,000 in 1995.
8. INCOME TAXES
At December 31, 1997, the tax-related regulatory assets and liabilities were $22 million and $38 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.
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NOTES (continued) Mississippi Power Company 1997 Annual Report
Details of the federal and state income tax provisions are shown below:
1997 1996 1995 --------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $27,651 $29,888 $32,546 Deferred --current year 8,171 13,816 5,122 --reversal of prior years (9,236) (14,913) (7,039) --------------------------------------------------------------- 26,586 28,791 30,629 --------------------------------------------------------------- State -- Currently payable 5,537 3,588 3,426 Deferred --current year 1,756 4,727 2,270 --reversal of prior years (2,499) (3,556) (833) --------------------------------------------------------------- 4,794 4,759 4,863 --------------------------------------------------------------- Total 31,380 33,550 35,492 Less income taxes charged to other income (588) 932 1,006 --------------------------------------------------------------- Federal and state income taxes charged to operations $31,968 $32,618 $34,486 ===============================================================
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:
1997 1996 ----------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $149,941 $148,667 Basis differences 10,037 10,507 Other 25,097 19,285 ------------------------------------------------------------- Total 185,075 178,459 ------------------------------------------------------------- Deferred tax assets: Other property basis differences 23,139 24,434 Pension and other benefits 9,803 8,750 Property insurance 5,351 4,955 Unbilled fuel 802 2,808 Other 19,714 11,302 ------------------------------------------------------------- Total 58,809 52,249 ------------------------------------------------------------- Net deferred tax liabilities 126,266 126,210 Portion included in current assets, net 8,379 7,227 ------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $134,645 $133,437 =============================================================
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $1.2 million in 1997, $1.4 million in 1996, and $1.5 million in 1995. At December 31, 1997, 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:
1997 1996 1995 ----------------------------- Total effective tax rate 37% 37% 38% State income tax, net of federal income tax benefit (3) (3) (3) Tax rate differential 1 1 - ------------------------------------------------------------- Statutory federal tax rate 35% 35% 35% =============================================================
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NOTES (continued) Mississippi Power Company 1997 Annual Report
Mississippi Power and the subsidiaries of Southern Company file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
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 $36 million aggregate principal amount of the Company's 7.75 percent junior subordinated notes due February 15, 2037.
10. OTHER LONG-TERM DEBT
Details of pollution control obligations and other long-term debt are as follows:
December 31, 1997 1996 --------------------- (in thousands) Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: 5.8$% due 2007 $ 950 $ 960 Variable rate due 2020 6,550 6,550 Variable rate due 2022 16,750 16,750 6.20% due 2023 13,000 13,000 5.65% due 2023 25,875 25,875 Variable due 2025 10,600 10,600 ------------------------------------------------------------ 73,725 73,735 ------------------------------------------------------------ Other long-term debt: Variable rates (6.10875% to 6.18984% at 1/1/98) due 1999 50,000 50,000 Variable rate due 2000 30,000 30,000 ------------------------------------------------------------ 80,000 80,000 ------------------------------------------------------------ Total $153,725 $153,735 ============================================================
Pollution control obligations represent installment or lease purchases of pollution control facilities financed by application of funds derived from sales by public authorities of tax-exempt revenue bonds. Mississippi Power has authenticated and delivered to the Trustee a like principal amount of first mortgage bonds as security for obligations under collateralized installment agreements. The principal and interest on the first mortgage bonds will be payable only in the event of default under these agreements. The 5.80% series of pollution control obligations has a cash sinking fund requirement of $20 thousand annually in 1998, 1999, 2000 and 2001.
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 is as follows:
1997 1996 ------------------- (in thousands) Bond improvement fund requirements $ 1,750 $1,750 Less: Portion to be satisfied by certifying property additions 1,750 1,750 ------------------------------------------------------------- Redemptions of first mortgage bonds 35,000 - Pollution control bond cash sinking fund requirements (Note 10) 20 10 ------------------------------------------------------------- Total $35,020 $ 10 =============================================================
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.
12. COMMON STOCK DIVIDEND RESTRICTIONS
Mississippi Power's first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 1997, 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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NOTES (continued) Mississippi Power Company 1997 Annual Report
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1997 and 1996 are as follows:
Net Income After Dividends Quarter Operating Operating On Ended Revenues Income Preferred Stock -------------------------------------------------------------------
March 1997 $116,903 $17,132 $ 10,645 June 1997 128,915 19,340 12,618 September 1997 171,874 30,441 25,163 December 1997 125,896 11,043 5,584
March 1996 $126,954 $18,074 $ 11,695 June 1996 136,749 17,691 11,400 September 1996 156,603 27,670 21,784 December 1996 123,723 13,636 7,844
Mississippi Power's business is influenced by seasonal weather conditions and the timing of rate changes.
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STATEMENTS OF INCOME Mississippi Power Company
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STATEMENTS OF INCOME Mississippi Power Company
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( ) Denotes use of cash.
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BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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MISSISSIPPI POWER COMPANY
SECURITIES RETIRED DURING 1997
Pollution Control Bonds Principal Interest Series Amount Rate - ------------------------------------------------------------------------------- (Thousands) 1977 $ 10 5.80%
Preferred Stock Principal Dividend Series Amount Rate - ------------------------------------------------------------------------------- (Thousands) 1947 $ 1,136 4.60% 1956 3,052 4.40% 1965 3,330 4.72% 1992 35,000 7.25% ------- $42,518 =======
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SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Savannah Electric and Power Company 1997 Annual Report
The management of Savannah Electric and Power Company has prepared--and is responsible for--the financial statements and related information included in this report. These statements were prepared in accordance with generally accepted accounting principles appropriate in the circumstances and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that books and records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of four directors who are not employees, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls and financial reporting matters. The internal auditors and the independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Savannah Electric and Power Company in conformity with generally accepted accounting principles.
/s/G. Edison Holland, Jr. G. Edison Holland, Jr. President and Chief Executive Officer
/s/K. R. Willis K. R. Willis Vice-President Treasurer, Secretary and Chief Financial Officer
February 11, 1998 II-227
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of 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, 1997 and 1996, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-235 through 11-246) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
/s/Arthur Andersen LLP Atlanta, Georgia February 11, 1998
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 1997 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 1997 totaled $23.8 million, representing a $0.1 million decrease from the prior year. This (0.4) percent change in earnings from 1996 is principally the result of an increase in other operation expense, partially offset by an increase in other income, net.
In 1996, earnings were $23.9 million, representing a $0.5 million (2.3 percent) increase from the prior year. This was principally the result of increased retail energy sales primarily attributable to an increase in the number of customers served.
Revenues
Total revenues for 1997 were $226.3 million, reflecting a (3.3) percent decrease compared to 1996. The following table summarizes revenue increases and decreases compared to prior years:
Increase (Decrease) From Prior Year -------------------------------------- 1997 1996 1995 -------------------------------------- Retail -- (in thousands) Sales growth $ 7,664 $ 3,679 $ 1,068 Weather (6,186) (2,813) 6,232 Fuel cost recovery and other (10,002) 12,365 6,177 ------------------------------------------------------------------- Total retail (8,524) 13,231 13,477 ------------------------------------------------------------------- Sales for resale-- Non-affiliates 1,469 147 (2,935) Affiliates (1,078) (4,070) 754 ------------------------------------------------------------------- Total sales for resale 391 (3,923) (2,181) ------------------------------------------------------------------- Other operating revenues 336 (963) 2,648 ------------------------------------------------------------------- Total operating revenues $(7,797) $ 8,345 $13,944 =================================================================== Percent change (3.3)% 3.7% 6.6% -------------------------------------------------------------------
Retail revenues declined 3.7 percent in 1997, compared to an increase of 6.2 percent in 1996. The decline in 1997 retail revenues is attributable to the mild summer weather and a decrease in fuel cost recovery revenues, somewhat offset by customer growth and higher demand from a large industrial customer. Under the Company's fuel cost recovery provisions, fuel revenues--including purchased energy--generally equal fuel expense and have no effect on earnings.
The increase in 1996 retail revenues was attributable to an increase in the number of customers served and an increase in fuel cost recovery revenues. Industrial energy sales were lower primarily due to a decrease in the demand of a major customer.
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. Capacity revenues remained unchanged in 1997. The capacity and energy components were as follows:
1997 1996 1995 ---------------------------------------- (in thousands) Capacity $ 2 $ 2 $ 3 Energy 746 1,329 1,250 - --------------------------------------------------------- Total $748 $1,331 $1,253 =========================================================
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 have little impact on earnings.
Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1997 and the percent change by year were as follows:
KWH Percent Change ------------ --------------------------- 1997 1997 1996 1995 ------------ --------------------------- (millions) Residential 1,428 (1.9)% 3.9% 8.0% Commercial 1,156 1.3 3.8 5.1 Industrial 881 5.1 (5.5) 11.0 Other 125 (1.4) 0.1 5.4 ------------ Total retail 3,590 0.8 1.4 7.7 Sales for resale Non-affiliates 94 2.9 4.4 (56.5) Affiliates 55 30.4 (34.4) (31.5) ------------ Total 3,739 1.2 % 0.8% 3.1% ===================================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1997 Annual Report
Expenses
Total operating expenses for 1997 were $189.1 million, reflecting a $6.1 million decrease from 1996. Major components of this decrease include a $16.5 million reduction in purchased power from affiliates, partially offset by increases of $6.4 million in fuel and $3.7 million in other operation expenses. The decline in purchased power from affiliates was due primarily to an increase in internal generation and to an adjustment in affiliated billings. The increase in fuel expense was primarily attributable to higher generation and to fuel mix. The increase in other operation expense primarily resulted from a one-time charge for work force reductions of $1.9 million, and expenses associated with the implementation of a new computer software system.
In 1996, total operating expenses were $195.2 million, reflecting an $7.7 million increase over 1995. This increase includes $5.3 million in purchased power from affiliates and $3.8 million in fuel, partially offset by a $1.2 million reduction in other operation expenses. The increase in purchased power from affiliates was due to an increase in the unit cost of purchased power. The increase in fuel expense was primarily attributable to higher generation and an increase in the unit cost of gas. The reduction in other operation expense primarily resulted from the demand-side management program being discontinued in December 1995.
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, the average cost of fuel per net kilowatt-hour generated, the average cost of purchased power per net kilowatt-hour, and the total average cost of energy supply were as follows:
1997 1996 1995 -------------------------- Total energy supply (millions of kilowatt-hours) 3,964 3,917 3,908 Sources of energy supply (percent) -- Coal 34 28 24 Oil - - - Gas 5 3 6 Purchased Power 61 69 70 Average cost of fuel per net Kilowatt-hour generated (cents) -- Coal 1.91 1.76 1.77 Oil 4.73 5.79 5.14 Gas 4.62 8.89 3.76 Average cost of purchased power per net kilowatt- hour (cents) 1.86 2.25 2.02 Total average cost of energy supply (cents) 2.02 2.30 2.07 ---------------------------------------------------------------
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 long-lived utility plant. 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 stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1997 Annual Report
Future Earnings Potential
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors ranging from energy sales growth to a less regulated, more competitive environment.
Savannah Electric currently operates as a vertically integrated utility providing electricity to customers within the traditional service area of southeastern Georgia. Prices for electricity provided by the Company to retail customers are set by the Georgia Public Service Commission(GPSC).
Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area.
The electric utility industry in the United States is currently undergoing a period of dramatic change as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Company is positioning the business to meet the challenge of this major change in the traditional practice of selling electricity. The Energy Act allows independent power producers (IPPs) to access the Company's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for industrial and commercial customers and sell energy generation to other utilities. Also, electricity sales for resale rates are being driven down by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers.
Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. As these initiatives materialize, the structure of the utility industry could radically change. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been or are being discussed in Georgia, none have been enacted to date. Enactment would require numerous issues to be resolved, including significant ones relating to transmission pricing and recovery of any stranded investments. The inability of the Company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on the financial condition of the Company. The Company is attempting to minimize or reduce its cost exposure.
Continuing to be a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, unless the Company remains a low-cost producer and provides quality service, the Company's retail energy sales growth could be limited, and this could significantly erode earnings.
The Company is heavily dependent upon complex computer systems for all phases of its operations. The year 2000 issue--common to most corporations--concerns the inability of certain software and databases to properly recognize date sensitive information related to the year 2000 and thereafter. This problem could result in a material disruption to the Company's operation, if not corrected. The Company has assessed and developed a detailed strategy to prevent or at least minimize problems related to the year 2000 issue. In 1997, resources were committed and implementation began to modify the affected information systems. Total costs related to the project for Southern Company are estimated to be approximately $85 million, of which $8 million was spent in 1997. The Company's total costs related to the project are estimated to be approximately $1 million, of which $0.2 million was spent in 1997. Most all remaining costs will be expensed in 1998. Implementation is currently on schedule. The degree of success of this project cannot be determined at this time. However, management believes that the final outcome will not have a material adverse affect on the operations of the Company.
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."
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Rates to retail customers served by the Company are regulated by the GPSC. As part of the Company's most recent rate settlement in 1992, it was informally agreed that the Company's earned rate of return on common equity should be 12.95 percent. The Company is currently undergoing an earnings review by the GPSC, and to date, the GPSC has made no determination.
The Company is subject to the provisions of Financial Accounting Standards Board 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 statement as incurred. At December 31, 1997, exposure from these activities was not material to the Company's financial statements.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which will be effective in 1998. This statement establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. The objective of the statement is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners (comprehensive income). Comprehensive income is the total of net income and all other non-owner changes in equity. The Company will adopt this statement in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an Enterprise and Related Information. This statement requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Generally, financial information is required to be reported on the basis that it is used by the chief operating decision maker in deciding how to allocate resources and in assessing performance. This statement also establishes standards for related disclosures about products and services, geographic areas, and major customers. The Company adopted the new rules in 1997, which do not have a significant impact on the Company's financial reporting. However, this conclusion may change as industry restructuring and competitive factors influence the Company's operations.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1997 was the addition of $19 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, 1997, the Company's capital structure consisted of 49.7 percent common equity, 9.9 percent preferred stock and 40.4 percent long-term debt, excluding amounts due within one year. The Company's long-term financial objective for capitalization ratios is to maintain a capital structure of common equity at 48 percent, preferred stock at 10 percent and debt at 42 percent.
In April 1997, the Company issued $14 million of variable interest rate pollution control obligations maturing in 2037. Maturities and retirements of long-term debt were $14 million in 1997, $29 million in 1996 and $29 million in 1995.
In March 1996, the Company entered into a fifteen year variable rate capital lease agreement with the Savannah Economic Development Authority for a coal ship docking and unloading facility at Plant Kraft.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1997 Annual Report
The composite interest rates and dividend rate for the years 1995 through 1997 as of year-end were as follows:
1997 1996 1995 ------------------------------- Composite interest rates on long-term debt 6.9% 7.0% 7.5% Preferred stock dividend rate 6.6% 6.6% 6.6% - ---------------------------------------------------------------
The Company's current securities ratings are as follows: Standard Moody's & Poor's --------------------------
First Mortgage Bonds A1 AA- Preferred Stock "a2" A - -----------------------------------------------------------------
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $66 million ($22 million in 1998, $23 million in 1999, and $21 million in 2000). 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. The Company does not have any traditional baseload generating plants under construction, and current energy demand forecasts do not require any additional traditional baseload facilities until well into the future. 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 $23 million will be needed by the end of 2000 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. This compliance strategy resulted in unused emission allowances being banked for later use. Construction expenditures for Phase I compliance totaled approximately $2 million for Savannah Electric.
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as necessary to meet Phase II limits. Current compliance strategy for Phase II and ozone non-attainment could require total estimated construction expenditures for Southern Company of approximately $70 million, of which $55 million remains to be spent. Phase II compliance is not expected to have a material impact on Savannah Electric.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national ambient air quality standards for ozone and particulate matter. This revision makes the standards significantly more stringent. Also, in October 1997, the EPA issued a proposed regional ozone rule that could require substantial further reductions in NOx emissions from fossil-fueled generating facilities. Implementation of the standards and the proposed rule could result in significant additional compliance costs and capital expenditures that cannot be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: emission control strategies for ozone non-attainment areas; additional controls for hazardous air pollutant
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emissions; and hazardous waste disposal requirements. The impact of new standards will depend on the development and implementation of applicable regulations.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur 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, 1997, the Company had $6.1 million of cash and $20.5 million of unused short-term credit arrangements with banks to meet its short-term cash needs. Revolving credit arrangements of $20 million, which expire December 31, 2000, are also used to meet short-term cash needs and to provide additional interim funding for the Company's construction program. Of the revolving credit arrangements, $20 million remained unused at December 31, 1997.
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. The Company plans to issue unsecured debt in 1998. 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. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.
Cautionary Statement Regarding Forward-Looking Information
Savannah Electric and Power Company's 1997 Annual Report contains forward-looking statements in addition to 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 statements; 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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PAGE> NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Savannah Electric and Power Company (the Company), is a wholly owned subsidiary of Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions, and other direct and indirect subsidiaries. The operating companies provide electric service in four southeastern states. Contracts among the companies--dealing with jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern Communications provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Worldwide, Southern Energy develops and manages electricity and other energy related projects, including domestic energy trading and marketing. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Company Energy Solutions develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company also is subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). The Company follows generally accepted accounting principles and complies with the accounting policies and practices prescribed by the GPSC. The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates, and the actual results may differ from those estimates.
Certain prior years' data presented in the financial statements have been reclassified to conform with the current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to:
1997 1996 --------------------------- (in thousands) Deferred income taxes $ 17,267 $ 19,167 Premium on reacquired debt 7,121 7,142 Deferred income tax credits (21,469) (22,792) Storm damage reserves (1,500) (900) - --------------------------------------------------------------- Total $ 1,419 $ 2,617 ===============================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related net regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The Company 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, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1997, uncollectible accounts continued to average less than 1 percent of revenues.
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Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 1997, 2.8 percent in 1996 and 2.9 percent in 1995. 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.
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 9.24 percent in 1997, 8.69 percent in 1996 and 7.42 percent in 1995.
Utility Plant
Utility plant is stated at original cost, which includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and AFUDC. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the 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 amounts did not equal fair value at December 31 were as follows:
Long-Term Debt -------------------------- Carrying Fair Year Amount Value -------------------------- (in millions) 1997 $158 $161 1996 155 161 - --------------------------------------------------------------
The fair values for long-term debt 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.
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.
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. Effective January 1, 1998, Savannah Electric and Power Company's pension plan was merged with the Southern Company plan. Benefits are based on the greater of amounts resulting from two different formulas: years of service and final average pay or years of service and a flat-dollar benefit. The Company uses the "projected unit credit" actuarial
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method for funding purposes, subject to limitations under federal income tax regulations. Amounts funded to the pension trust are primarily invested in equity and fixed-income securities. FASB Statement No. 87, Employers' Accounting for Pensions, requires use of the "projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
The Company also provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations and to the extent required by the GPSC and the FERC. Amounts funded are primarily invested in equity and fixed--income securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, requires that medical care and life insurance benefits for retired employees be accounted for on an accrual basis using a specified actuarial method, "benefit/years-of-service." The cost of postretirement benefits is reflected in rates on a current basis.
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the Balance Sheets at December 31 are as follows:
Pension --------------------------- 1997 1996 --------------------------- (in thousands) Actuarial present value of benefit obligation: Vested benefits $40,240 $39,270 Non-vested benefits 3,350 2,939 - ---------------------------------------------------------------- Accumulated benefit obligation 43,590 42,209 Additional amounts related to projected salary increases 8,130 7,705 - ---------------------------------------------------------------- Projected benefit obligation 51,720 49,914 Less: Fair value of plan assets 51,630 42,430 Unrecognized net loss 1,275 7,147 Unrecognized prior service cost 1,884 1,240 Unrecognized net transition obligation 355 444 - ---------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 3,424 $ 1,347 ================================================================
Postretirement Benefits ------------------------- 1997 1996 -------------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $12,509 $12,442 Employees eligible to retire 1,923 1,614 Other employees 6,467 6,464 - ------------------------------------------------------------- Accumulated benefit obligation 20,899 20,520 Less: Fair value of plan assets 3,859 2,473 Unrecognized net loss 3,737 4,835 Unrecognized transition Obligation 7,407 7,900 - ------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 5,896 $ 5,312 =============================================================
The weighted average rates assumed in the actuarial calculations for the pension plan were:
1997 1996 1995 -------------------------- Discount 7.50% 7.25% 7.25% Annual salary increase 5.00 4.75 4.75 Long-term return on plan assets 8.50 8.75 8.75 ---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.8 percent for 1997, decreasing gradually to 5.5 percent through the year 2005 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated benefit obligation at December 31, 1997, by $1.4 million and the aggregate of the service and interest cost components of the net postretirement cost by $0.1 million.
Components of the plans' net costs are shown below:
Pension ----------------------------- 1997 1996 1995 ----------------------------- (in thousands) Benefits earned during the year $1,393 $1,352 $1,188 Interest cost on projected benefit obligation 3,556 3,389 3,395 Actual (return) loss on plan assets (7,762) (4,852) (5,791) Net amortization and deferral 4,735 2,439 4,125 - ------------------------------------------------------------------ Net pension cost $1,922 $2,328 $2,917 ==================================================================
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Of the above net pension costs, $1.7 million in 1997, $2.0 million in 1996 and $2.4 million in 1995 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits ----------------------------- 1997 1996 1995 ----------------------------- (in thousands) Benefits earned during the year $ 319 $ 360 $ 504 Interest cost on accumulated benefit obligation 1,499 1,422 1,638 Amortization of transition Obligation 494 494 723 Actual (return) loss on plan assets (346) (145) (34) Net amortization and deferral 260 187 93 - ------------------------------------------------------------------ Net postretirement costs $2,226 $2,318 $2,924 ==================================================================
Of the above net postretirement costs, $1.9 million in 1997, $2.0 million in 1996 and $2.4 million in 1995 were recorded in operating expenses. The remainder for each year was charged to construction and other accounts.
The Company has a supplemental retirement plan for certain executive employees. The plan is unfunded and payable from the general funds of the Company. The Company has purchased life insurance on participating executives, and plans to use these policies to satisfy this obligation. Benefit costs associated with this plan were $0.4 million for 1997, 1996 and 1995.
3. REGULATORY MATTERS
Rates to retail customers served by the Company are regulated by the GPSC. As part of the Company's most recent rate settlement in 1992, it was informally agreed that the Company's earned rate of return on common equity should be 12.95 percent. The Company is currently undergoing an earnings review by the GPSC, and to date, the GPSC has made no determination.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently estimated to total $22 million in 1998, $23 million in 1999 and $21 million in 2000. 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 cost 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 and extension of the useful lives of generating plants will continue.
5. FINANCING AND COMMITMENTS
General
To the extent possible, the Company's construction program is expected to be financed from internal sources and from the issuance of additional long-term debt, preferred stock and capital contributions from Southern Company.
The amounts of long-term debt and preferred stock 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 1997, unused credit arrangements with five banks totaled $20.5 million and expire at various times during 1998.
The Company's revolving credit arrangements of $20 million, of which $20 million remained unused as of December 31, 1997, expire December 31, 2000. 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
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property and a second lien for a $14 million bank note is secured by a portion of the Plant McIntosh property.
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $1.2 million for 1997, $1.6 million for 1996, and $1.3 million for 1995. The Company entered into a 22.5 year lease agreement effective December 1, 1995 for 100 new aluminum rail cars at an annual cost of approximately $0.5 million. The rail cars are used to transport coal to one of the Company's generating plants.
At December 31, 1997, estimated future minimum lease payments for non-cancelable operating leases were as follows:
Amounts -------------------- (in thousands) 1998 $1,077 1999 483 2000 483 2001 483 2002 and thereafter 7,935 - -------------------------------------------------------------
6. INCOME TAXES
At December 31, 1997, tax-related regulatory assets and liabilities were $17 million and $21 million, respectively. The assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. The liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
Details of income tax provisions are as follows:
1997 1996 1995 -------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $9,743 $ 7,084 $10,427 Deferred -- current year 4,522 8,216 5,290 -- reversal of prior years (1,381) (1,989) (1,661) - ----------------------------------------------------------------- 12,884 13,311 14,056 - ----------------------------------------------------------------- State -- Currently payable 1,603 575 1,941 Deferred -- current year 569 1,216 695 -- reversal of prior years 130 39 35 - ----------------------------------------------------------------- 2,302 1,830 2,671 - ----------------------------------------------------------------- Total 15,186 15,141 16,727 Less income taxes credited to other income (1,233) (1,034) (651) - ----------------------------------------------------------------- Total income taxes charged to operations $16,419 $16,175 $17,378 =================================================================
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:
1997 1996 -------------------- Deferred tax liabilities: (in thousands) Accelerated depreciation $72,663 $67,104 Property basis differences 8,034 9,550 Other 5,850 5,703 - ---------------------------------------------------------------- Total 86,547 82,357 - ---------------------------------------------------------------- Deferred tax assets: Pension and other benefits 5,338 5,183 Other 2,957 2,186 - ---------------------------------------------------------------- Total 8,295 7,369 - ---------------------------------------------------------------- Net deferred tax liabilities 78,252 74,988 Portions included in current assets, net 2,445 1,666 - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $80,697 $76,654 ================================================================
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $0.7 million in 1997, 1996 and 1995. At December 31, 1997, all investment tax credits available to reduce federal income taxes payable had been utilized.
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A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
1997 1996 1995 ----------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of federal income tax benefit 4 3 4 Other (2) (1) - -------------------------------------------------------------- Effective income tax rate 37% 37% 39% ==============================================================
Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
7. CUMULATIVE PREFERRED STOCK
The Company has outstanding 1,400,000 shares of 6.64% Series Preferred Stock which has redemption provisions of $26.66 per share plus accrued dividends if redeemed on or prior to November 1, 1998, and redemption provisions of $25 per share plus accrued dividends thereafter. Cumulative preferred stock dividends are preferential to the payment of dividends on common stock.
8. LONG-TERM DEBT
The Company's Indenture related to its First Mortgage Bonds is unlimited as to the authorized amount of bonds which may be issued, provided that required property additions, earnings and other provisions of such Indenture are met.
In April 1997, the Company issued $14 million in variable rate pollution control obligations (bank note) maturing in 2037. The Company redeemed all of its remaining outstanding 6 3/4% Pollution Control Bonds due 2022.
The sinking fund requirements of first mortgage bonds were satisfied by certifying property additions in 1997 and by cash redemption in 1996. The 1998 requirement will be satisfied by cash redemption. Sinking fund requirements and/or maturities through 2002 applicable to long-term debt are as follows: $21.8 million in 1998; $0.6 million in 1999; $0.6 million in 2000; $10.5 million in 2001; and $0.4 million in 2002.
Details of pollution control obligations and other long-term debt at December 31 are as follows:
1997 1996 ------------------------ (in thousands) Collateralized obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds -- Variable rate (4.20% at 1/1/98) due 2016 $ 4,085 $ 4,085 6 3/4% due 2022 - 13,870 Variable rate bank note (5.05% at 1/1/98) due 2037 13,870 - Capital lease obligations -- Coal unloading facility Variable rate (6.25% at 1/1/98) 5,867 6,667 Transportation fleet 788 421 Notes Payable -- 6.88% due 2001 10,000 10,000 Variable rate (6.06% at 1/1/98) due 1998 15,000 15,000 Variable rate (6.06% at 1/1/98) due 1998 5,000 5,000 - ---------------------------------------------------------------- Total $54,610 $55,043 ================================================================
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.
In March 1996, the Company entered into a fifteen year variable rate capital lease agreement with the Savannah Economic Development Authority for a coal ship docking and unloading facility at Plant Kraft.
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9. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the sinking fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
1997 1996 ------------------------- (in thousands) Bond sinking fund requirement $ 1,100 $1,100 Less: Portion to be satisfied by certifying property additions - 1,100 - -------------------------------------------------------------------- Cash sinking fund requirement 1,100 - Other long-term debt maturities (Note 8) 20,664 637 - -------------------------------------------------------------------- Total $21,764 $ 637 ====================================================================
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.
10. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Charter and Indenture contain certain limitations on the payment of cash dividends on preferred and common stocks. At December 31, 1997, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Indenture.
11. QUARTERLY FINANCIAL INFORMATIO (Unaudited)
Summarized quarterly financial data for 1997 and 1996 are as follows (in thousands):
Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock - -----------------------------------------------------------------
March 1997 $42,945 $ 6,117 $ 2,545 June 1997 52,516 8,626 5,136 September 1997 79,900 17,531 14,276 December 1997 50,916 4,950 1,890
March 1996 $50,575 $ 6,562 $ 2,740 June 1996 61,906 9,786 5,859 September 1996 73,359 16,542 12,815 December 1996 48,234 5,994 2,526 - -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
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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 1998 annual meeting of stockholders. The ages of directors and executive officers in Item 10 set forth below are as of December 31, 1997.
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 58 Served as Director since 3-1-89
Bill M. Guthrie Executive Vice President Age 64 Served as Director since 12-16-88
Whit Armstrong (2) Age 50 Served as Director since 9-24-82
A. W. Dahlberg (2) Age 57 Served as Director since 4-22-94
Peter V. Gregerson, Sr. (2) Age 69 Served as Director since 10-22-93
Carl E. Jones, Jr. (2) Age 57 Served as Director since 4-22-88
Patricia M. King (2) Age 52 Served as Director since 7-25-97
James K. Lowder (2) Age 48 Served as Director since 7-25-97
Wallace D. Malone, Jr. (2) Age 61 Served as Director since 6-22-90
William V. Muse (2) Age 58 Served as Director since 2-26-93
John T. Porter (2) Age 66 Served as Director since 10-22-93
Robert D. Powers (2) Age 47 Served as Director since 1-24-92
Andreas Renschler (2) Age 39 Served as Director since 1-23-98
C. Dowd Ritter (2) Age 50 Served as Director since 7-25-97
John W. Rouse (2) Age 60 Served as Director since 4-22-88
William J. Rushton, III (2) Age 68 Served as Director since 9-18-70
James H. Sanford (2) Age 53 Served as Director since 8-1-83
John C. Webb, IV (2) Age 55 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 25, 1997) for one year until the next annual meeting or until a successor is elected and qualified, except for Ms. King, Mr. Lowder, Mr. Renschler and Mr. Ritter 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 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 58 Served as Executive Officer since 3-1-89
Banks H. Farris Executive Vice President Age 62 Served as Executive Officer since 12-3-91
Michael D. Garrett Executive Vice President - External Affairs Age 48 Served as Executive Officer since 3-1-98
William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer Age 54 Served as Executive Officer since 12-3-91
Charles D. McCrary (2) Executive Vice President Age 46 Served as Executive Officer since 1-1-91
(1) Previously served as executive officer of ALABAMA from 1979 to 1985. (2) Resigned effective March 1, 1998, upon being elected Executive Vice President of SOUTHERN's Fossil/Hydro Group.
Each of the above is currently an executive officer of ALABAMA, serving a term running from the last annual meeting of the directors (April 25, 1997) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Garrett whose election was effective on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as 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 - Elected in 1989; Chief Executive Officer. Director of SOUTHERN and AmSouth Bancorporation.
Bill M. Guthrie - Elected in 1988; also served since 1991 as Chief Production Officer of the SOUTHERN system and from 1991 to 1994 as Executive Vice President and Chief Production Officer of SCS. Elected Senior Executive Vice President and Chief Production Officer of SCS effective 1994. Also serves as Vice President of SOUTHERN, GULF, MISSISSIPPI and SAVANNAH and Executive Vice President of GEORGIA. Responsible primarily for providing overall management of materials management, fuel services, operating and planning services, fossil, hydro and bulk power operations of the Southern electric system.
Whit Armstrong - President, Chairman and Chief Executive Officer of The Citizens Bank, Enterprise, Alabama. Also, President and Chairman of the Board of Enterprise Capital Corporation, Inc. Director of Enstar Group, Inc.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of SOUTHERN since 1995. He previously served as President of SOUTHERN from 1994 to 1995 and President and Chief Executive Officer of GEORGIA from 1988 through 1993. Director of SOUTHERN, GEORGIA, Equifax, Inc., Protective Life Corporation and SunTrust Banks, Inc.
Peter V. Gregerson, Sr. - Chairman Emeritus of Gregerson's Foods, Inc. (retail groceries), Gadsden, Alabama.
Carl E. Jones, Jr. - President and Chief Executive Officer of Regions Financial Corporation, Birmingham, Alabama. He previously served as President and Chief Operating Officer of Regions Financial Corporation.
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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.
Wallace D. Malone, Jr. - Chairman and Chief Executive Officer of SouthTrust Corporation, bank holding company, Birmingham, Alabama. Director of American Cast Iron Pipe Company.
William V. Muse - President of Auburn University. Director of SouthTrust Bank and American Cast Iron Pipe Company.
John T. Porter - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama. Director of Citizens Federal Savings Bank.
Robert D. Powers - President and Director, The Eufaula Agency, Inc. (real estate and insurance), Eufaula, Alabama.
Andreas Renschler - President and Chief Executive Officer of Mercedes-Benz U.S. International, Inc., Tuscaloosa County, Alabama.
C. Dowd Ritter - Chairman, President, Chief Executive Officer and Director, AmSouth Bancorporation and AmSouth Bank, Birmingham, Alabama.
John W. Rouse - President of The Rouse Group, LLC, (technology consulting), Birmingham, Alabama and President Emeritus of Southern Research Institute. Director of Protective Life Corporation.
William J. Rushton, III - Chairman Emeritus of the Board, Protective Life Corporation (insurance holding company), Birmingham, Alabama. Director of SOUTHERN.
James H. Sanford - Chairman, HOME Place Farms Inc. (diversified farmers and ginners), Prattville, Alabama. Chairman of the Board, Sylvest Farms of Georgia, Inc., College Park, Georgia. Chairman of the Board, Sylvest Poultry Inc., Montgomery, Alabama.
John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber and wood products sales), Demopolis, Alabama. Director, J. F. Suttle, Co.
Banks H. Farris - Elected in 1991; responsible primarily for providing the overall management of human resources, information resources, power delivery and marketing departments, customer service centers and the six geographic divisions. He previously served as Senior Vice President from 1991 to 1994.
Michael D. Garrett - Elected in 1998; responsible for external relations department, public relations and corporate services. He previously served as Senior Vice President - External Affairs from February 1994 to March 1998.
William B. Hutchins, III - Elected in 1991; responsible for financial and accounting operations, corporate planning and treasury operations. He previously served as Senior Vice President and Chief Financial Officer from 1991 to 1994 and as Executive Vice President and Chief Financial Officer from 1994 to 1998.
Charles D. McCrary - Elected in 1991; responsible for the external relations department, public relations and corporate services. He previously served as Senior Vice President from 1991 to 1994.
Involvement in certain legal proceedings. None.
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GEORGIA
Identification of directors of GEORGIA.
H. Allen Franklin President and Chief Executive Officer Age 53 Served as Director since 1-1-94
Warren Y. Jobe Executive Vice President and Chief Financial Officer Age 57 Served as Director since 8-1-82
Daniel P. Amos (1) Age 46 Served as Director since 5-21-97
Juanita P. Baranco (1) Age 48 Served as Director since 5-21-97
A. W. Dahlberg (1) Age 57 Served as Director since 6-1-88
William A. Fickling, Jr. (1) Age 65 Served as Director since 4-18-73
L. G. Hardman III (1) Age 58 Served as Director since 6-25-79
James R. Lientz, Jr. (1) Age 54 Served as Director since 7-21-93
G. Joseph Prendergast (1) Age 52 Served as Director since 1-20-93
Herman J. Russell (1) Age 67 Served as Director since 5-18-88
Gloria M. Shatto (1) Age 66 Served as Director since 2-20-80
William Jerry Vereen (1) Age 57 Served as Director since 5-18-88
Carl Ware (1) (2) Age 54 Served as Director since 2-15-95
Thomas R. Williams (1) Age 69 Served as Director since 3-17-82
(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 21, 1997) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he/she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GEORGIA acting solely in their capacities as such.
Identification of executive officers of GEORGIA.
H. Allen Franklin President, Chief Executive Officer and Director Age 53 Served as Executive Officer since 1-1-94
Warren Y. Jobe (1) Executive Vice President, Chief Financial Officer and Director Age 57 Served as Executive Officer since 5-19-82
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William C. Archer, III Executive Vice President - External Affairs Age 49 Served as Executive Officer since 4-6-95
Gene R. Hodges Executive Vice President - Customer Operations Age 59 Served as Executive Officer since 11-19-86
David M. Ratcliffe Executive Vice President and Treasurer Age 49 Served as Executive Officer since 3-1-98
William P. Bowers Senior Vice President - Marketing Age 41 Served as Executive Officer since 9-22-95
Wayne T. Dahlke Senior Vice President - Power Delivery Age 56 Served as Executive Officer since 4-19-89
James K. Davis Senior Vice President - Corporate Relations Age 57 Served as Executive Officer since 10-1-93
Robert H. Haubein Senior Vice President - Fossil/Hydro Power Age 57 Served as Executive Officer since 2-19-92
Fred D. Williams Senior Vice President - Resource Policy & Planning Age 53 Served as Executive Officer since 11-18-92
(1) Elected Senior Vice President of SOUTHERN in February 1998; however, Mr. Jobe will maintain his present position as Executive Vice President, Chief Financial Officer and Director of GEORGIA.
Each of the above is currently an executive officer of GEORGIA, serving a term running from the last annual meeting of the directors (May 21, 1997) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Ratcliffe whose election was effective on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of GEORGIA acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
H. Allen Franklin - President and Chief Executive Officer since 1994. He previously served as President and Chief Executive Officer of SCS from 1988 through 1993. Director of SOUTHERN and SouthTrust Corporation.
Warren Y. Jobe - Executive Vice President and Chief Financial Officer since 1982 and Treasurer from 1992 to 1998. Responsible for financial and accounting operations and planning, internal auditing, procurement, corporate secretary and treasury operations.
Daniel P. Amos - President and Chief Executive Officer, American Family Life Assurance Company (AFLAC), Columbus, Georgia. Director, AFLAC Incorporated (and subsidiaries), CIT Group and Greystone Capital Partners, I.L.P.
Juanita P. Baranco - Business owner of Baranco Automotive Group. Director of Federal Reserve Bank of Atlanta and John H. Harland Company, Decatur, Georgia.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of SOUTHERN since 1995. He previously served as President of SOUTHERN from 1994 to 1995 and President and Chief Executive Officer of GEORGIA from 1988 through 1993. Director of SOUTHERN, ALABAMA, Equifax, Inc., Protective Life Corporation and SunTrust Banks, Inc.
William A. Fickling, Jr. - Chairman of the Board, Chief Executive Officer of Beech Street Corporation (provider of managed care services) and President from 1995 to 1996. He previously served as Chairman of the Board and Chief Executive Officer of Charter Medical Corporation (provider of psychiatric care).
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L. G. Hardman III - Chairman of the Board of The First National Bank of Commerce, Georgia and Chairman of the Board and Chief Executive Officer of First Commerce Bancorp, Inc. Chairman of the Board, President and Treasurer of Harmony Grove Mills, Inc. (real estate investments). Director of SOUTHERN.
James R. Lientz, Jr. - President of NationsBank of Georgia since 1993. He previously served as President and Chief Executive Officer of former Citizens & Southern Bank of South Carolina (now NationsBank) from 1990 to 1993. Director of Cerulean Companies, Inc. and Blue Cross/Blue Shield of Georgia.
G. Joseph Prendergast - Senior Executive Vice President, Wachovia Corporation. Heads the banking division comprising the companies consumer and corporate banking activities and Wachovia Bank, N.A. Chairman, Wachovia Bank of Georgia, Wachovia Bank of South Carolina and Wachovia Bank of North Carolina since 1994. Director, Willamette Industries, Portland, Oregon.
Herman J. Russell - Chairman of the Board, H. J. Russell & Company (construction), Atlanta, Georgia. Chairman of the Board, Citizens Trust Bank, Atlanta, Georgia. Director of Wachovia Corporation and First Union Real Estate and Mortgage Investments.
Gloria M. Shatto - President, Berry College, Mount Berry, Georgia. Director of SOUTHERN, Becton Dickinson & Company and Texas Instruments, Inc.
William Jerry Vereen - President, Treasurer and Chief Executive Officer of Riverside Manufacturing Company (manufacture and sale of uniforms), Moultrie, Georgia. Director of Gerber Scientific, Inc., Textile Clothing Technology Corporation, Cerulean Companies, Inc. and Blue Cross/Blue Shield of Georgia.
Carl Ware - President, Africa Group, The Coca-Cola Company since 1991.
Thomas R. Williams - President of The Wales Group, Inc. (investments), Atlanta, Georgia. Director of ConAgra, Inc., National Life Insurance Company of Vermont, AppleSouth, Inc., American Software, Inc. and The Fidelity Group of Funds.
William C. Archer, III - Executive Vice President - External Affairs since September 1995. Senior Vice President - External Affairs from April 1995 to September 1995. Vice President - Human Resources for SCS from 1992 to 1995.
Gene R. Hodges - Executive Vice President - Customer Operations, Power Delivery and Safety.
David M. Ratcliffe - Executive Vice President - Finance and Treasurer since 3-1-98. Responsible for accounting, corporate secretary, finance and procurement. He previously served as Senior Vice President - External Affairs of SOUTHERN from 1995 to 1998. President and Chief Executive Officer of MISSISSIPPI from 1991 to 1995.
William P. Bowers - Senior Vice President - Marketing since 1995. Vice President - - Retail Sales and Service from 1992 to 1995. Director of Georgia MedCorp, Inc., Southern Regional Medical Center and Georgia MedCorp Development Corporation.
Wayne T. Dahlke - Senior Vice President - Power Delivery since 1992. Senior Vice President - Marketing from 1989 to 1992.
James K. Davis - Senior Vice President - Corporate Relations since 1993. Vice President of Corporate Relations from 1988 to 1993.
Robert H. Haubein - Senior Vice President - Fossil/ Hydro Power since 1994. Senior Vice President - Administrative Services from 1992 to 1994 and Vice President - Northern Region from 1990 to 1992.
Fred D. Williams - Senior Vice President - Resource Policy and Planning since 1997. Senior Vice President - Wholesale Power Marketing from 1995 to 1997. Senior Vice President - Bulk Power Markets from 1992 to August 1995. In addition, he was elected Senior Vice President - Wholesale Power Marketing of SCS in 1995 and Senior Vice President of ALABAMA in February 1996.
Involvement in certain legal proceedings. None.
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GULF
Identification of directors of GULF.
Travis J. Bowden President and Chief Executive Officer Age 59 Served as Director since 2-1-94
Paul J. DeNicola (1) Age 49 Served as Director since 4-19-91
Fred C. Donovan (1) Age 57 Served as Director since 1-18-91
W. Deck Hull, Jr. (1) Age 65 Served as Director since 10-14-83
Joseph K. Tannehill (1) Age 64 Served as Director since 7-19-85
Barbara H. Thames (1) Age 57 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 24, 1997) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GULF acting solely in their capacities as such. Identification of executive officers of GULF.
Travis J. Bowden President, Chief Executive Officer and Director Age 59 Served as Executive Officer since 2-1-94
Francis M. Fisher, Jr. Vice President - Power Delivery and Customer Operations Age 49 Served as Executive Officer since 5-19-89
John E. Hodges, Jr. Vice President - Marketing and Employee/External Affairs Age 54 Served as Executive Officer since 5-19-89
Robert G. Moore Vice President - Power Generation and Transmission Age 48 Served as Executive Officer since 7-25-97
Arlan E. Scarbrough Vice President - Finance Age 61 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 25, 1997) 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.
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Identification of certain significant employees. None.
Family relationships. None.
Business experience.
Travis J. Bowden - Elected President effective February 1994 and, effective May 1994, Chief Executive Officer. He previously served as Executive Vice President of ALABAMA from 1985 to 1994.
Paul J. DeNicola - President and Chief Executive Officer of SCS since 1994. He previously served as Executive Vice President of SCS from 1991 through 1993. Director of SOUTHERN, MISSISSIPPI and SAVANNAH.
Fred C. Donovan - President of Baskerville - Donovan, Inc., Pensacola, Florida, an architectural and engineering firm.
W. Deck Hull, Jr. - President and Director of Hull Oil Company - Panama City, Florida. He previously served as Vice Chairman of the SunTrust Bank, West Florida, Panama City, Florida.
Joseph K. Tannehill - President and Chief Executive Officer of Merrick International Industries, Lynn Haven, Florida. Director of Regions Bank of North Florida, Panama City, Florida.
Barbara H. Thames - Chief Executive Officer of Santa Rosa Medical Center, Milton, Florida.
Francis M. Fisher, Jr. - Elected Vice President - Employee and External Relations in 1989 and, effective August 1996, Vice President - Power Delivery and Customer Operations.
John E. Hodges, Jr. - Elected Vice President - Customer Operations in 1989 and, effective August 1996, Vice President - Marketing and Employee/External Affairs.
Robert G. Moore - Elected Vice President - Power Generation and Transmission of GULF and Vice President of Fossil Generation of SCS in 1997. He previously served as Plant Manager - Bowen at GEORGIA.
Arlan E. Scarbrough - Elected Vice President - Finance in 1980; responsible for all accounting and financial services of GULF.
Involvement in certain legal proceedings. None.
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MISSISSIPPI
Identification of directors of MISSISSIPPI.
Dwight H. Evans President and Chief Executive Officer Age 49 Served as Director since 3-27-95
Paul J. DeNicola (1) Age 49 Served as Director since 5-1-89
Edwin E. Downer (1) Age 66 Served as Director since 4-24-84
Robert S. Gaddis (1) Age 66 Served as Director since 1-21-86
Walter H. Hurt, III (1) Age 62 Served as Director since 4-6-82
Aubrey K. Lucas (1) Age 63 Served as Director since 4-24-84
George A. Schloegel (1) Age 57 Served as Director since 7-26-95
Philip J. Terrell (1) Age 44 Served as Director since 2-22-95
N. Eugene Warr (1) Age 62 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 1, 1997) for one year until the next annual meeting or until his successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of MISSISSIPPI acting solely in their capacities as such.
Identification of executive officers of MISSISSIPPI.
Dwight H. Evans President, Chief Executive Officer and Director Age 49 Served as Executive Officer since 3-27-95
H. E. Blakeslee Vice President - Customer Services and Marketing Age 57 Served as Executive Officer since 1-25-84
Andrew J. Dearman, III Vice President - Power Generation and Delivery Age 44 Served as Executive Officer since 4-23-97
Don E. Mason Vice President - External Affairs and Corporate Services Age 56 Served as Executive Officer since 7-27-83
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer Age 45 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 23, 1997) for one year until the next annual meeting or until his successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of MISSISSIPPI acting solely in their capacities as such.
Identification of certain significant employees. None. III-9
Family relationships. None.
Business experience.
Dwight H. Evans - President and Chief Executive Officer since 1995. He previously served as Executive Vice President of GEORGIA from 1989 to 1995.
Paul J. DeNicola - President and Chief Executive Officer of SCS effective 1994. Executive Vice President of SCS from 1991 through 1993. Director of SOUTHERN, SAVANNAH and GULF.
Edwin E. Downer - Business consultant specializing in economic analysis, management controls and procedural studies.
Robert S. Gaddis - Chairman of the Advisory Board of Trustmark National Bank, Laurel, Mississippi.
Walter H. Hurt, III - President and Director of NPC Inc. (Investments). Vicar of All Saints' Episcopal Church, Inverness, Mississippi, and St. Thomas Church, Belzoni, Mississippi.
Aubrey K. Lucas - President Emeritus and Distinguished Professor of Higher Education at the University of Southern Mississippi, Hattiesburg, Mississippi.
George A. Schloegel - President of Hancock Bank and Hancock Bank Securities Corporation. Vice Chairman of Hancock Holding Company. Director of Hancock Bank - Mississippi and Hancock Bank - Louisiana.
Philip J. Terrell - Superintendent of Pass Christian Public School District and adjunct professor at William Carey College.
N. Eugene Warr - Retailer (Biloxi and Gulfport, Mississippi). Director of Coast Community Bank, formerly SouthTrust Bank of Mississippi, Biloxi, Mississippi.
H. E. Blakeslee - Elected Vice President in 1984. Primarily responsible for rate design, revenue forecasting, marketing, district operations, corporate compliance, distribution engineering, customer account and customer call center.
Andrew J. Dearman, III - Elected Vice President in 1997. Primarily responsible for generating plants, environmental quality, fuel services, power generation technical services, transmission, system planning, bulk power contracts, system operations and control, system protection and real estate. He served as Vice President - Southern Division of ALABAMA from 1995 to May 1997, and Division Manager - Customer Service of ALABAMA from 1989 to 1995.
Don E. Mason - Elected Vice President in 1983. Primarily responsible for external affairs, corporate communications, security, risk management, economic development and general services, as well as the human resources function.
Michael W. Southern - Elected Vice President, Secretary, Treasurer and Chief Financial Officer in 1995. Primarily responsible for accounting, secretary/treasury, corporate planning, procurement and information resources. He previously served as Director of Corporate Finance of SCS from 1994 to 1995 and Director of Financial Planning of SCS from 1990 to 1994.
Involvement in certain legal proceedings. None.
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SAVANNAH
Identification of directors of SAVANNAH.
G. Edison Holland, Jr. President and Chief Executive Officer Age 45 Served as Director since 5-20-97
Archie H. Davis (1) Age 56 Served as Director since 2-18-97
Paul J. DeNicola (1) Age 49 Served as Director since 3-14-91
Walter D. Gnann (1) Age 62 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 52 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 61 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 20, 1997) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he/she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of SAVANNAH acting solely in their capacities as such.
Identification of executive officers of SAVANNAH.
G. Edison Holland, Jr. President, Chief Executive Officer and Director Age 45 Served as Executive Officer since 10-1-97
W. Miles Greer Vice President - Marketing and Customer Services Age 54 Served as Executive Officer since 11-20-85
Larry M. Porter Vice President - Operations Age 52 Served as Executive Officer since 7-1-91
Kirby R. Willis Vice President, Treasurer, Chief Financial Officer and Assistant Corporate Secretary Age 46 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 last annual meeting of the directors (July 15, 1997) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Holland whose election was effective on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of SAVANNAH acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
G. Edison Holland, Jr. - Elected President and Chief Executive Officer in 1997. Vice President - Power Generation/Transmission and Corporate Counsel of Gulf Power Company from 1995 to 1997. Served as a partner in the law firm of Beggs & Lane from 1979 to 1997.
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.
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Paul J. DeNicola - President and Chief Executive Officer of SCS since 1994. Executive Vice President of SCS from 1991 through 1993. Director of SOUTHERN, GULF and MISSISSIPPI.
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc., Springfield, Georgia. Past Chairman of the Development Authority of Effingham County, Georgia.
Robert B. Miller, III - President of American Building Systems, Inc.
Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation. Director of First Union Bank of Georgia, First Union Bank of Savannah, Cerulean Corporation and Blue Cross/Blue Shield of Georgia.
W. Miles Greer - Vice President - Marketing and Customer Services effective 1994. Formerly served as Vice President - Economic Development and Corporate Services from 1989 through 1993.
Larry M. Porter - Vice President - Operations since 1991. Responsible for managing the areas of fuel procurement, power production, transmission and distribution, engineering and system operation.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since 1994 and Assistant Corporate Secretary effective 1998. Responsible primarily for all accounting, financial, information resources, labor relations, corporate services, environmental and safety activities. He previously served as Treasurer, Controller and Assistant Secretary from 1991 to 1993.
Involvement in certain legal proceedings. None.
Section 16(a) Beneficial Ownership Reporting Compliance.
GEORGIA's Messrs. Jobe and Vereen each failed to file on a timely basis a single report disclosing one transaction on Form 5 as required by Section 16 of the Securities Act of 1934.
GULF's Ms. Thames and Mr. Moore each failed to file on a timely basis a single report disclosing one transaction on Form 3 as required by Section 16 of the Securities Act of 1934. Ms. Thames executed a Form 3 on the day of the reporting event for mailing by GULF; however, GULF inadvertently submitted the report two days late.
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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 1997 for each of the operating affiliates (ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH).
See next page for footnotes.
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DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Pension Plan Table. The following table sets forth the estimated combined annual pension benefits under the Pension, Supplemental Defined Benefit, and Supplemental Executive Retirement Plans in effect during 1997 for the named executives at ALABAMA, GEORGIA, GULF and MISSISSIPPI and Messrs. Gignilliat and Holland at SAVANNAH. Employee compensation covered by the Pension, Supplemental Benefit, and Supplemental Executive Retirement Plans for pension purposes is limited to the average of the highest three of the final 10 years' compensation - -- base salary plus the excess of annual and long-term incentive compensation over 25 percent of base salary (reported under column titled "Salary", "Bonus", and "Long-Term Incentive Payouts" in the Summary Compensation Tables on pages III-13 through III-18).
The amounts shown in the table were calculated according to the final average pay formula and are based on a single life annuity without reduction for joint and survivor annuities (although married employees are required to have their pension benefits paid in one of various joint and survivor annuity forms, unless the employee elects otherwise with the spouse's consent) or computation of the Social Security offset which would apply in most cases. This offset amounts to one-half of the estimated Social Security benefit (primary insurance amount) in excess of $3,900 per year times the number of years of accredited service, divided by the total possible years of accredited service to normal retirement age.
As of December 31, 1997, 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 $839,724 39 Banks H. Farris 372,912 38 Charles D. McCrary 324,528 23 William B. Hutchins, III 306,456 31
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GEORGIA Compensation Accredited Name Level Years of Service
H. Allen Franklin $908,664 26 Warren Y. Jobe1 334,656 26 Gene R. Hodges 331,092 33 Robert H. Haubein, Jr. 312,216 30 William C. Archer 258,780 26
GULF Compensation Accredited Name Level Years of Service
Travis J. Bowden2 $471,636 31 Arlan E. Scarbrough 236,436 34 John E. Hodges, Jr. 242,940 31 Francis M. Fisher, Jr. 218,364 26 Robert G. Moore 166,296 24
MISSISSIPPI Compensation Accredited Name Level Years of Service
Dwight H. Evans $360,732 26 H. E. Blakeslee 264,744 32 Don E. Mason 254,556 31 Michael W. Southern 205,272 22 Andrew J. Dearman, III 162,552 22
SAVANNAH Compensation Accredited Name Level Years of Service
Arthur M. Gignilliat $354,456 37 G. Edison Holland, Jr.3 255,768 15 Larry M. Porter 139,788 20 W. Miles Greer 133,860 13 Kirby R. Willis 126,180 23
1 The number of accredited years of service includes 8 years credited to Mr. Jobe pursuant to a supplemental pension agreement. 2 The number of accredited years of service includes 10 years credited to Mr. Bowden pursuant to a supplemental pension agreement. 3 The number of accredited years of service includes 10 years credited to Mr. Holland pursuant to a supplemental pension agreement.
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SAVANNAH has in effect a qualified, trusteed, noncontributory, defined benefit pension plan which provides pension benefits to employees upon retirement at the normal retirement age after designated periods of accredited service and at a specified compensation level. The plan provides pension benefits under a formula which includes each participant's years of service with the Southern system and average annual earnings (excluding incentive compensation) of the highest three of the final 10 years of service with the Southern system preceding retirement. Plan benefits are reduced by a portion of the benefits participants are entitled to receive under Social Security. The plan provides for reduced early retirement benefits at age 55 and a pension for the surviving spouse equal to one-half of the deceased retiree's pension.
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 SAVANNAH'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 SAVANNAH's pension and supplemental executive retirement plans in effect during 1997 which are payable to SAVANNAH's named executives, except Messrs. Gignilliat and Holland who participate 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.
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Compensation of Directors.
Standard Arrangements. The following table presents compensation paid to the directors, during 1997 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, 1997 in addition to or in lieu of that specified by the standard arrangements specified above.
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Employment Contracts and Termination of Employment and Change in Control Arrangements.
None.
Report on Repricing of Options.
None.
Compensation Committee Interlocks and Insider Participation.
None.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security ownership of certain beneficial owners. SOUTHERN is the beneficial owner of 100% of the outstanding common stock of registrants: ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH.
Security ownership of management. The following table shows the number of shares of SOUTHERN common stock and operating subsidiary preferred stock owned by the directors, nominees and executive officers as of December 31, 1997. 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, 1997.
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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. Ritter is Chairman, President, Chief Executive Officer and Director of AmSouth Bancorporation and AmSouth Bank, Birmingham, Alabama. During 1997, these banks furnished a number of regular banking services in the ordinary course of business to ALABAMA. ALABAMA intends to maintain normal banking relations with all the aforesaid banks in the future.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
GEORGIA
Transactions with management and others.
Mr. L. G. Hardman III is Chairman of the Board of The First National Bank of Commerce, Georgia; Mr. James R. Lientz, Jr. is President of NationsBank of Georgia, Atlanta, Georgia; Mr. G. Joseph Prendergast is Chairman of Wachovia Bank of Georgia, N.A., Atlanta, Georgia; and Mr. Herman J. Russell is Chairman of the Board of Citizens Trust Bank, Atlanta, Georgia. During 1997, 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 1997, GEORGIA leased a building from Riverside Manufacturing Co. for approximately $80,511. Also, Riverside Manufacturing sold to GEORGIA fire retardant uniforms for $104,687. 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.
Mr. W. Deck Hull, Jr. was Vice Chairman of SunTrust Bank, West Florida, Panama City, Florida from 1993 to 1997. During 1997, this bank furnished a number of regular banking services in the ordinary course of business to GULF. GULF intends to maintain normal banking relations with the aforesaid bank in the future.
In 1997, GULF paid to Merrick Industries, Inc. $303,782 for replacement parts for existing equipment and for the purchase and installation of coal feeders for Plant Smith. Mr. Tannehill is President and Chief Executive Officer of Merrick Industries, Inc.
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 1997, 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.
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Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
SAVANNAH
Transactions with management and others. None
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
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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