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), Southern Development and other direct and indirect subsidiaries. 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. A further description of Southern Energy's business and organization follows later in this section under "New Business Development." 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. Southern Development 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
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" herein.)
Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions.
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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 Power Company, 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, Southern Development 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.
New Business Development
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 to increase its aggregate 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 with U.S. Court of Appeals for the 11th Circuit seeking judicial review of the SEC Order. At December 31, 1996, SOUTHERN's consolidated retained earnings amounted to $3,764 million, and its aggregate investment in EWGs and FUCOs, after giving effect to the CEPA acquisition discussed below, amounted to $2,524 million.
Southern Energy develops, builds, owns and operates both cogeneration and independent power production and delivery facilities in the North American and international market. Southern Energy's trading and marketing subsidiary provides power marketing and energy trading services to wholesale and retail customers in North America.
Reference is made to Note 15 to the financial statements of SOUTHERN in Item 8 herein for additional information regarding SOUTHERN's business segments and geographic areas.
In 1995, SOUTHERN acquired SWEB, one of the United Kingdom's 12 regional electric distribution companies, for approximately $1.8 billion. SWEB is, to some extent, involved in power generation and certain non-regulated activities which include gas supply and telecommunications. In early 1997, SOUTHERN acquired an 80% interest in CEPA for a total net investment of $2.1 billion.
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CEPA is engaged in the business of developing, constructing, owning and operating electric power generation facilities. Its current operations include installed operating capacity of approximately 3,995 megawatts, with projects either completed or under development in the Philippines, the People's Republic of China, Indonesia and Pakistan. 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, 1996, 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 -----------
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Nameplate Generating Station Location Capacity ----------------------------------------------------------------- (Kilowatts)
McIntosh Effingham County, GA 163,117 Kraft Port Wentworth, GA 281,136 Riverside Savannah, GA 102,278 ----------- SAVANNAH Total 546,531 -----------
Gaston Units 1-4 Wilsonville, AL (SEGCO) 1,000,000 (7) ----------- Total Fossil Steam 21,700,243 -----------
Nuclear Steam Farley Dothan, AL (ALABAMA) 1,720,000 ----------- Hatch Baxley, GA 840,250 (8) Vogtle Augusta, GA 1,060,240 (9) ----------- GEORGIA Total 1,900,490 ---------- Total Nuclear Steam 3,620,490 -----------
Combustion Turbines Greene County Demopolis, AL (ALABAMA) 720,000 ----------- Arkwright Macon, GA 30,580 Atkinson Atlanta, GA 78,720 Bowen Cartersville, GA 39,400 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 1,847,822 ---------
Lansing Smith Unit A (GULF) Panama City, FL 39,400
Chevron Cogenerating Station Pascagoula, MS 147,292 (10) 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 3,094,054 --------- 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 (11) 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 31,075,248
---------------------------------------------- -----------------
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) Generation is dedicated to a single industrial customer. (11) 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 Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. 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, 1996, the unamortized portion of this cost was $39 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 that time was 9.4%. For additional information on peak demands, reference is made to Item 6 SELECTED FINANCIAL DATA herein.
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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, 1996, 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 declining fractions of OPC's and MEAG's capacity and energy from this plant. The declining commitments were in effect during periods of up to seven years following commercial operation and ended in 1996. The commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG 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 net investment in the plant is approximately $175 million, and GEORGIA's ownership is 25.4 percent. 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 150-megawatt unit, with use of 100% of the capacity from June through September. FPC has the capacity the remainder of the year. GEORGIA's investment in the unit is approximately $13 million.
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.
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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, 1992 to December 31, 1996, 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 (1) $2,318 $ 383 GEORGIA (2) 2,730 1,633 GULF 347 130 MISSISSIPPI 441 86 SAVANNAH 189 16 SEGCO 60 9 SCS 108 122 Southern Nuclear 7 5 Southern Communications 194 - Southern Energy 318 22 ---------------------------------------------------------- SOUTHERN system $6,712 $2,406 ==========================================================
Notes: (1) Includes approximately $62 million attributable to sale of 8.2% interest in Plant Miller Units 1 and 2 to AEC in 1992. (2) Includes approximately $446 million attributable to 1992 through 1996 sales of Plant Scherer Unit 4 to FP&L and JEA.
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Item 3.
Item 3. LEGAL PROCEEDINGS
(1) Stepak v. certain SOUTHERN officials (U.S. District Court for the Southern District of Georgia)
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8 herein under the caption "Stockholder Suit Concluded."
(2) SOUTHERN and Subsidiaries v. Commissioner of the IRS (U.S. Tax Court)
In June 1994, a tax deficiency notice was received from the IRS for the years 1984 through 1987 with regard to the tax accounting by GEORGIA for the sale in 1984 of an interest in Plant Vogtle and related capacity and energy buyback commitments. The potential tax deficiency and interest arising from this issue currently amount to approximately $25 million and $32 million, respectively. The tax deficiency relates to a timing issue as to when taxes are paid; therefore, only the interest portion could affect future income. Management believes that the IRS position is incorrect, and GEORGIA has filed a petition with the U.S. Tax Court challenging the IRS's position. In order to minimize additional interest charges should the IRS's position prevail, GEORGIA made a payment to the IRS related to the potential tax deficiency in September 1994. In conjunction with this matter, SOUTHERN has filed certain refund claims related to the years 1984 through 1987. SOUTHERN and the IRS have entered into negotiations on all issues, the outcome of which is currently uncertain.
(3) 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.
(4) GEORGIA has been designated as a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act with respect to a site in Brunswick, Georgia.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein under the captions "Georgia Power Potentially Responsible Party Status" and "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, Southern Development 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
None.
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EXECUTIVE OFFICERS OF SOUTHERN
(Identification of executive officers of SOUTHERN is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 1996.
A. W. Dahlberg Chairman, President and Chief Executive Officer Age 56 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 48 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 52 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 57 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 48 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.
W. L. Westbrook Financial Vice President, Chief Financial Officer and Treasurer Age 57 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 47 Elected in 1995; President and Chief Executive Officer of Southern Energy since 1992. He previously served as Senior Vice President of GEORGIA from 1989 to 1992.
Bill M. Guthrie Vice President Age 63 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 52 President and Chief Executive Officer of Southern Nuclear since 1993. He has also served as Executive Vice President of GEORGIA since 1989.
Each of the above is currently an officer of SOUTHERN, serving a term running from the last annual meeting of the directors (May 22, 1996) for one year until the next annual meeting or until his successor is elected and qualified.
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PART II
Item 5.
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) The common stock of SOUTHERN is listed and traded on the New York Stock Exchange. The stock is also traded on regional exchanges across the United States. High and low stock prices, per the New York Stock Exchange Composite Tape during each quarter for the past two years were as follows:
----------------------------------------------------- High Low ----------- -------- First Quarter $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
First Quarter $21-1/2 $19-3/8 Second Quarter 22-7/8 20-1/8 Third Quarter 24 21-1/8 Fourth Quarter 25 22-3/4 -----------------------------------------------------
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 28, 1997, the closing price of SOUTHERN's common stock was $21-3/4.
(b) Number of SOUTHERN's common stockholders at December 31, 1996: 215,246
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 1996 1995 ----------------------------------------------------
SOUTHERN First $211,081 $201,866 Second 211,272 203,060 Third 212,200 203,061 Fourth 212,201 203,178
ALABAMA First 76,000 71,900 Second 76,400 69,500 Third 76,400 69,300 Fourth 118,700 74,300
GEORGIA First 121,500 113,900 Second 122,100 110,200 Third 122,100 109,700 Fourth 109,800 117,700
GULF First 12,300 11,700 Second 12,400 11,300 Third 12,400 11,300 Fourth 21,200 12,100
MISSISSIPPI First 10,600 9,900 Second 10,700 9,600 Third 10,600 9,600 Fourth 12,000 10,300
SAVANNAH First 4,800 4,400 Second 4,800 4,300 Third 4,800 4,300 Fourth 5,200 4,600 ----------------------------------------------------
The dividend paid per share by SOUTHERN was 30.5(cent) for each quarter of 1995 and 31.5(cent) for each quarter of 1996. The dividend paid on SOUTHERN's common stock for the first quarter of 1997 was raised to 32.5(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 respective first mortgage bond indenture and 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, 1996, were as follows:
---------------------------------------------------------- Retained Restricted Earnings Amount ------------------ -------------- (in millions)
ALABAMA $1,185 $ 796 GEORGIA 1,675 897 GULF 179 127 MISSISSIPPI 166 118 SAVANNAH 109 68 Consolidated 3,764 2,008 - --------------------------------------------------------
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-37 through II-52.
ALABAMA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-80 through II-93.
GEORGIA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-126 through II-140.
GULF. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-168 through II-181.
MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-208 through II-221.
SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-243 through II-255.
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-14.
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-56 through II-61.
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-97 through II-103.
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-144 through II-150.
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-185 through II-191.
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-225 through II-229.
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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 1996 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 12, 1997
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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, 1996 and 1995, 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, 1996. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements (pages II-15 through II-36) referred to above present fairly, in all material respects, the financial position of Southern Company and subsidiary companies as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Atlanta, Georgia February 12, 1997
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 1996 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
Southern Company's 1996 financial results exceeded the strong performance recorded in 1995. The traditional core business of selling electricity in the Southeast remained strong, while non-traditional business results reflected a full year of South Western Electricity's (SWEB) operations. The acquisition of SWEB in late 1995 by Southern Energy, Inc. (Southern Energy) made a significant positive impact on non-traditional earnings. Net income of over $1.1 billion and earnings per share of $1.68 for 1996 both established record highs. Net income increased $24 million compared with the amount reported for 1995. Continued cost controls, steady demand for electricity, and growth in the non-traditional business were the dominant forces that favorably affected 1996 earnings.
Costs related to work force reduction programs decreased earnings by $53 million or 8 cents per share and $17 million or 2 cents per share in 1996 and 1995, respectively. These costs are expected to be recovered through future savings in approximately two years following each program's implementation.
In 1995, earnings were $1.1 billion or $1.66 per share -- up 14 cents from the per share amount reported in 1994. Earnings in 1995 were affected by a reduction in costs related to work force reduction programs, and much hotter temperatures when compared with 1994 results.
Dividends paid on common stock during 1996 were $1.26 per share or 31 1/2 cents per quarter. During 1995 and 1994, dividends paid per share were $1.22 and $1.18, respectively. In January 1997, the Southern Company board of directors raised the quarterly dividend to 32 1/2 cents per share or an annual rate of $1.30 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 acquisition of Consolidated Electric Power Asia (CEPA) closed in January 1997, and is not included in Southern Company's 1996 results. Southern Energy did acquire several businesses in late 1995 and 1994. These businesses have been included in the consolidated financial statements since the date of acquisition and are not reflected in prior periods. Therefore, changes in revenues and expenses for 1996 and for 1995 reflect significant amounts related to acquisitions, which were not fully reflected in each year being compared. To facilitate discussing the results of operations, Southern Energy's variances are shown separately and are predominantly acquisition related.
Revenues
Operating revenues increased in 1996 and 1995 as a result of the following factors:
Increase (Decrease) From Prior Year --------------------------------- 1996 1995 1994 ---------------------------------- Retail -- (in millions) Change in base rates $ (18) $ - $ 3 Sales growth 142 177 153 Weather (64) 143 (177) Fuel cost recovery and other 2 134 (107) --------------------------------------------------------------- Total retail 62 454 (128) --------------------------------------------------------------- Sales for resale -- Within service area 10 39 (87) Outside service area 14 (90) (108) --------------------------------------------------------------- Total sales for resale 24 (51) (195) Southern Energy 1,040 458 131 Other operating revenues 52 22 - --------------------------------------------------------------- Total operating revenues $1,178 $883 $192) =============================================================== Percent change 12.8% 10.6% (2.3)% ---------------------------------------------------------------
Retail revenues of $7.7 billion in 1996 increased 0.8 percent from last year, compared with an increase of 6.4 percent in 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 $409 million in 1996, up 2.5 percent from the prior year. Revenues from sales for resale within the service area were $399 million in 1995, up 11 percent from the prior year. This increase in 1995 resulted primarily from the prolonged hot summer weather, which increased the demand for electricity.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1996 Annual Report
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost.
1996 1995 1994 ---------------------------------- (in millions) Capacity $217 $237 $276 Energy 176 151 176 ------------------------------------------------------- Total $393 $388 $452 =======================================================
Capacity revenues decreased in 1996 because the amount of capacity under contract declined slightly in 1996 and by 100 megawatts in 1995. Additional declines in capacity are not scheduled until after 1999.
Changes in traditional core business revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1996 and the percent change by year were as follows:
(billions of kilowatt-hours) Amount Percent Change ------------- ---------------------------- 1996 1996 1995 1994 ------------- ---------------------------- Residential 40.1 2.5% 9.2% (2.6)% Commercial 38.0 5.7 5.5 3.8 Industrial 52.8 2.2 2.7 3.2 Other 0.9 5.7 2.1 3.8 ------------- Total retail 131.8 3.3 5.4 1.6 Sales for resale -- Within service area 10.9 15.4 16.2 (38.5) Outside service area 10.8 17.9 (15.1) (13.5) ------------- Total 153.5 5.0 4.4 (3.4) ===================================================================
The rate of increase in 1996 retail energy sales continued to be strong. The number of customers served increased by nearly 71,000 during the year. Residential energy sales experienced only moderate gains as a result of milder summer weather in 1996, compared with the extremely hot summer of 1995. Commercial and industrial sales continue to show slight gains in excess of the national average. 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 1997 through 2007.
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 1996 and declined in 1995 when compared with the prior year. However, these fluctuations in energy sales 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 $8.5 billion for 1996 increased $1.2 billion compared with the prior year. Traditional core business expenses increased $240 million. Southern Energy's expenses increased $970 million. The large increase for Southern Energy resulted primarily from SWEB, which was acquired in late 1995. The costs to 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. Depreciation expenses and property taxes increased by $50 million as a result of additional utility plant being placed into service. The amortization of deferred expenses related to Plant Vogtle increased by $13 million in 1996 when compared with the prior year.
In 1995, operating expenses of $7.3 billion increased 11 percent compared with 1994. Traditional core business expenses increased $322 million. Southern Energy's expenses increased $390 million. Total production costs for the core business were up $120 million. Depreciation expense and taxes other than income taxes increased $78 million. Also, the amortization of deferred Plant Vogtle expenses increased $49 million compared with the amount in 1994.
Fuel costs constitute the single largest expense for Southern Company. The mix of fuel sources for generation of electricity is determined primarily by
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1996 Annual Report
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:
1996 1995 1994 ---------------------------- Total generation (billions of kilowatt-hours) 156 147 142 Sources of generation (percent) -- Coal 77 77 75 Nuclear 17 17 19 Hydro 4 4 5 Oil and gas 2 2 1 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.65 1.73 1.80 Nuclear 0.52 0.56 0.56 Oil and gas 5.20 3.37 3.99 Total 1.48 1.53 1.56 - ---------------------------------------------------------------
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. The traditional core business's customer demand for electricity rose by 7.9 billion kilowatt-hours more than in 1995. The additional cost to meet the demand was offset slightly by a lower average cost of fuel per net kilowatt-hour generated. Fuel and purchased power expenses of $2.6 billion in 1995 increased $282 million compared with the prior year. Traditional core business accounted for $73 million of the increase because of higher energy sales.
For 1996, total income taxes decreased $12 million compared with the prior year. Traditional core business income taxes decreased $47 million, and Southern Energy increased $35 million. The decrease was attributable to less taxable income from core business operations. For 1995, income taxes rose $84 million above the amount reported for 1994. Traditional core business increased $65 million and Southern Energy accounted for the remainder.
Total gross interest charges and preferred stock dividends increased $19 million from amounts reported in the previous year. These costs for core business continued to decline by $71 million, but Southern Energy's interest charges increased. The decline in costs for core business was attributable to lower interest rates and continued refinancing activities in 1996. In 1995, these costs for core business decreased $12 million. As a result of favorable market conditions, $574 million in 1996, $1.1 billion in 1995, and $1.0 billion in 1994 of senior securities were issued for the primary purpose of retiring higher-cost securities.
Effects of Inflation
Southern 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 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 future earnings depends on numerous factors ranging from energy sales growth to a less regulated more competitive environment, with non-traditional business becoming more significant.
Work force reduction programs have reduced earnings by $53 million, $17 million, and $61 million for the years 1996, 1995, and 1994, respectively. These actions will assist in efforts to control growth in future operating expenses.
Future earnings in the near term will depend upon growth in energy 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. Southern Company is positioning its business to meet the challenge of this major change
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1996 Annual Report
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 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.
Various federal and state initiatives designed to promote wholesale and retail competition, among other things, include proposals that would allow customers to choose their electricity provider. As the initiatives materialize, the structure of the utility industry could radically change. Certain initiatives could result in a change in the ownership and/or operation of generation and transmission facilities. Numerous issues must be resolved, including significant ones relating to transmission pricing and recovery of stranded investments. Being a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. 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.
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 evolving opportunities, Southern Energy-- founded in 1981 -- is focusing on international and domestic cogeneration, the independent power market, and the privatization of generating and distribution facilities in the international market. As the marketplace evolves, Southern Energy is positioning the company to become a major competitor for providing energy-related services, including energy trading and marketing. Also, Southern Energy is expanding the business through acquisitions. In late 1995, SWEB was acquired for approximately $1.8 billion. In July 1996, a 25 percent interest in SWEB was sold. The acquisition of an 80 percent interest in CEPA for a total net investment of some $2.1 billion was completed in early 1997. For additional information on these acquisitions, see Note 14 to the financial statements.
The CEPA acquisition is expected to be slightly dilutive in the near term. However, Southern Energy's investments should increase the opportunities for long-term future earnings growth. At December 31, 1996, Southern Energy's total assets amounted to $4.9 billion, and with the inclusion of CEPA assets will be nearly $10 billion.
Rates to retail customers served by the system operating companies are regulated by the respective state public service commissions in Alabama, Florida, Georgia, and Mississippi. 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. See Note 3 to the financial statements for information about other retail and wholesale regulatory matters.
The staff of the Securities and Exchange Commission 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 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 the Clean Air Act Amendments of 1990 (Clean Air Act) 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) Southern Company and Subsidiary Companies 1996 Annual Report
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, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
FINANCIAL CONDITION
Overview
Southern Company's financial condition continues to remain strong. Earnings per share set a record high in 1996. Net income continued to increase in 1996 and exceeded $1.1 billion. Based on this performance, in January 1997, the Southern Company board of directors increased the common stock dividend for the sixth consecutive year.
Gross property additions to utility plant were $1.2 billion. The majority of funds needed for gross property additions since 1993 have been provided from operating activities, principally from earnings and non-cash charges to income such as depreciation and deferred income taxes. The Consolidated Statements of Cash Flows provide additional details.
Southern Company uses financial derivatives on a limited basis to mitigate business risks. At December 31, 1996, the credit and price risks for derivatives outstanding were not material to the financial statements. See Note 1 to the financial statements under "Financial Instruments" for additional information.
Capital Structure
Southern Company achieved a ratio of common equity to total capitalization -- including short-term debt -- of 45.1 percent in 1996, compared with 42.4 percent in 1995, and 44.4 percent in 1994. The company's goal is to maintain the common equity ratio generally within a range of 40 percent to 45 percent.
During 1996, the subsidiary companies sold $85 million of first mortgage bonds and, through public authorities, $167 million of pollution control revenue bonds. Preferred securities of $322 million were issued in 1996. The companies continued to reduce financing costs by retiring higher-cost bonds and preferred stock. Retirements, including maturities, of bonds totaled $600 million during 1996, $1.3 billion during 1995, and $973 million during 1994. Retirements of preferred stock totaled $179 million during 1996, and $1 million a year during 1995 and 1994. As a result, the composite interest rate on long-term debt decreased from 7.6 percent at December 31, 1993, to 6.9 percent at December 31, 1996. During this same period, the composite dividend rate on preferred stock declined from 6.4 percent to 6.2 percent.
In 1996, Southern Company raised $171 million from the issuance of new common stock under the company's various stock plans. At the close of 1996, the company's common stock had a market value of 22 5/8 per share, compared with a book value of $13.61 per share. The market-to-book value ratio was 166 percent at the end of 1996, compared with 188 percent at year-end 1995, and 160 percent at year-end 1994.
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $1.4 billion for 1997, $1.3 billion for 1998, and $1.4 billion for 1999. The total is $4.1 billion for the three years. 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 for the operating companies will be fully recovered.
The operating companies do not have any traditional baseload generating plants under construction, and current energy demand forecasts do not require any traditional baseload facilities until well into the future. Significant construction of transmission and distribution facilities and upgrading of generating plants will be continuing.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $1.2 billion will be required by the end of 1999 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1996 Annual Report
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- impacts 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.
In 1995, the Environmental Protection Agency (EPA) began issuing annual sulfur dioxide emission allowances through the allowance trading program. An emission allowance is the authority to emit one ton of sulfur dioxide during a calendar year. The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
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 $310 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. Therefore, current compliance strategy could require total Phase II estimated construction expenditures of approximately $80 million, of which $60 million remains to be spent. However, 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.
An average increase of up to 1 percent in revenue requirements from customers could be necessary to fully recover the cost of compliance for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include construction expenditures, increased costs for switching to low-sulfur coal, and costs related to emission allowances.
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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: revisions to the ambient air quality standards for ozone and particulate matter; 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 $8 million a year for 1995 and 1994. In 1996, the company was reimbursed $6 million for amounts previously expensed. Additional sites may require environmental remediation for which the subsidiaries may be liable for a portion or all required cleanup costs. See Note 3 to the financial statements for information regarding Georgia Power's potentially responsible party status at a site in Brunswick, Georgia.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of Southern Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect Southern Company. The impact of new legislation -- if
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 1996 Annual Report
any -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
Southern Company plans to issue additional equity capital in 1997. The amount and timing of additional equity capital to be raised in 1997 -- 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 1997 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 was primarily from internal sources. However, the type and timing of any financings - -- if needed -- will depend on market conditions and regulatory approval.
To meet short-term cash needs and contingencies, Southern Company had approximately $445 million of cash and cash equivalents and $4.1 billion of unused credit arrangements with banks at the beginning of 1997.
To issue additional first mortgage bonds and preferred stock, the operating companies must comply with certain earnings coverage requirements designated in their mortgage indentures and corporate charters. The ability to issue securities in the future will depend on coverages at that time. Currently, each of the operating companies expects to have adequate coverage ratios for anticipated requirements through at least 1999.
II-14
CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1996, 1995, and 1994 Southern Company and Subsidiary Companies 1996 Annual Report
The accompanying notes are an integral part of these statements.
II-15
CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1996, 1995, and 1994 Southern Company and Subsidiary Companies 1996 Annual Report
II-16
CONSOLIDATED BALANCE SHEETS At December 31, 1996 and 1995 Southern Company and Subsidiary Companies 1996 Annual Report
II-17
CONSOLIDATED BALANCE SHEETS At December 31, 1996 and 1995 Southern Company and Subsidiary Companies 1996 Annual Report
II-18
CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 1996 and 1995 Southern Company and Subsidiary Companies 1996 Annual Report
II-19
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 1996 and 1995 Southern Company and Subsidiary Companies 1996 Annual Report
II-20
NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 1996 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 Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear), The Southern Development and Investment Group (Southern Development), 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) 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 Development 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 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 majority-owned or controlled subsidiaries on a consolidated basis and other investments on an equity basis. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform with 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 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:
1996 1995 ------------------------ (in millions) Deferred income taxes $1,302 $1,386 Deferred Plant Vogtle costs 171 308 Premium on reacquired debt 289 295 Demand-side programs 44 79 Department of Energy assessments 69 73 Vacation pay 77 74 Deferred fuel charges 29 49 Postretirement benefits 38 53 Work force reduction costs 48 56 Deferred income tax credits (879) (936) Storm damage reserves (32) (23) Other, net 114 98 - ----------------------------------------------------------------- Total $1,270 $1,512 =================================================================
In the event that a portion of the operating companies' operations is no longer subject to the provisions of Statement No. 71, the companies would be required to write off related regulatory assets and liabilities. In addition, the operating companies would be required to determine any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The 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 and the energy component of purchased power costs. Revenues
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates.
The operating companies have a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1996, 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 $142 million in 1996, $140 million in 1995, and $152 million in 1994. 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 cast 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 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, 1996, under this law to be approximately $37 million and $30 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 3.3 percent in 1996, 3.3 percent in 1995, and 3.2 percent in 1994. 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 $24 million in 1996 and $6 million in 1995. See Note 3 under "Georgia Power Retail Accounting Order" for additional information.
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. Alabama Power and Georgia Power have external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the respective state public service commissions. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission a specific facility as of the site study year, and ultimate cost is the estimate to decommission a specific facility as of retirement date. The estimated costs of decommissioning
II-22
NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
- -- both site study costs and ultimate costs -- at December 31, 1996, 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 1994 1994
Decommissioning periods: Beginning year 2017 2014 2027 Completion year 2029 2027 2038 - ----------------------------------------------------------------- (in millions) Site study costs: Radiated structures $489 $294 $233 Non-radiated structures 89 41 52 - ----------------------------------------------------------------- Total $578 $335 $285 =================================================================
Ultimate costs: Radiated structures $1,504 $781 $1,018 Non-radiated structures 274 111 230 - ----------------------------------------------------------------- Total $1,778 $892 $1,248 =================================================================
Plant Plant Plant Farley Hatch Vogtle --------------------------- (in millions)
Amount expensed in 1996 $18 $11 $9
Accumulated provisions: Balance in external trust funds $149 $ 79 $51 Balance in internal reserves 47 27 13 - ---------------------------------------------------------------- Total $196 $106 $64 ================================================================
Significant assumptions: Inflation rate 4.5% 4.4% 4.4% Trust earning rate 7.0 6.0 6.0 - ----------------------------------------------------------------
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 included in cost of service. 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 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 1994 through 1996 ranged from a before-income-tax rate of 5.1 percent to 9.8 percent. AFUDC, net of income tax, as a percent of consolidated net income was 1.4 percent in 1996, 1.6 percent in 1995, and 2.3 percent in 1994.
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
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
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 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.
Financial Instruments
Southern Company engages in price risk management activities for trading and non-trading purposes. Activities for non-trading purposes consist of transactions that are employed to mitigate Southern Company's risk related to interest rate and foreign currency fluctuations. Gains and losses arising from effective hedges of existing assets, liabilities, or firm commitments are deferred and recognized when the offsetting gains and losses are recognized on the related hedged items. At December 31, 1996, the credit risk for derivatives outstanding was not material to the financial statements. Southern Company regularly monitors its foreign currency exposure and ensures that hedge contract amounts do not exceed the amount of underlying exposures. At December 31, 1996, the status of outstanding non-trading related derivative contracts was as follows:
Year Of Maturity or Notional Unrealized Type Termination Amount Gain (Loss) - ---------------------------------- --------------------------- (in millions) Interest rate swaps: 1999-2011 $158 $(7) 2001-2012 (pound)500 $(13) Cross currency swaps 2001-2006 (pound)405 $(38) - ----------------------------------------------------------------- (pound) - Denotes British pound sterling.
During 1996, Southern Energy began trading activities by offering price risk management services related to commodities associated with the domestic energy industry -- electricity and natural gas. Southern Energy provides these services through a variety of financial instruments. These transactions are accounted for using the mark-to-market method of accounting. Under this method, unrealized gains or losses resulting from the impact of price movements are recognized as net gains or losses in the consolidated statements of income. The market prices used to value these transactions reflect management's best estimates considering various factors including: closing exchange quotations, over-the-counter quotations, liquidity of the position, time value, and volatility factors underlying the commitments. Net trading gains and losses were insignificant to the financial statements for the year ended December 31, 1996. Also, outstanding contracts at December 31, 1996, were not material to the financial statements.
South Western Electricity (SWEB)--a British distribution company owned by Southern Energy--has 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 a portion of electricity purchases of approximately 28 billion kilowatt-hours through the year 2008. This represents approximately two years of electricity purchases for SWEB based on current volumes. Accordingly, the gains or losses realized on such contracts are deferred and recognized as electricity is purchased. It is not possible to estimate the fair value of these contracts due to the absence of a trading market.
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, 1996 $7,975 $8,122 At December 31, 1995 8,636 8,935 Preferred securities: At December 31, 1996 422 427 At December 31, 1995 100 114 - -----------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on either closing market price or closing price of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
2. RETIREMENT BENEFITS
Pension Plan
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. Trusts are funded to the extent deductible under federal income tax regulations or to the extent required by the operating companies' 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 is being expensed each succeeding year until the costs are 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.
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and postretirement insurance benefits as computed under the requirements of FASB Statement Nos. 87 and 106, respectively. The funded status of the plans at December 31 was as follows:
Pension ----------------------- 1996 1995 ----------------------- (in millions) Actuarial present value of benefit obligation: Vested benefits $2,730 $2,643 Non-vested benefits 119 97 - ------------------------------------------------------------------ Accumulated benefit obligation 2,849 2,740 Additional amounts related to projected salary increases 775 705 - ------------------------------------------------------------------ Projected benefit obligation 3,624 3,445 Less: Fair value of plan assets 5,212 4,725 Unrecognized net gain (1,314) (1,025) Unrecognized prior service cost 135 60 Unrecognized transition asset (114) (126) - ------------------------------------------------------------------ Prepaid asset recognized in the Consolidated Balance Sheets $ 295 $ 189 ==================================================================
Postretirement Benefits ---------------------------- 1996 1995 --------------- ------------ (in millions) Actuarial present value of benefit obligation: Retirees and dependents $409 $394 Employees eligible to retire 78 63 Other employees 383 392 - ------------------------------------------------------------------ Accumulated benefit obligation 870 849 Less: Fair value of plan assets 260 205 Unrecognized net loss (gain) 79 85 Unrecognized prior service cost (5) (4) Unrecognized transition obligation 249 292 - ------------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $287 $271 ===================================================================
In 1995, the system companies announced a cost sharing program for postretirement benefits. The program established limits on amounts the companies will pay to provide future retiree postretirement benefits. This change reduced the 1995 accumulated postretirement benefit obligation by approximately $186 million.
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
The weighted average rates assumed in the actuarial calculations were:
1996 1995 1994 --------------------------------- Discount 7.8% 7.3% 8.0% Annual salary increase 5.3 4.8 5.5 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 9.3 percent for 1996, decreasing gradually to 5.8 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, 1996, by $77 million and the aggregate of the service and interest cost components of the net retiree cost by $8 million.
Components of the plans' net costs are shown below:
Pension --------------------------- 1996 1995 1994 --------------------------- (in millions) Benefits earned during the year $ 99 $ 79 $ 77 Interest cost on projected benefit obligation 267 193 160 Actual (return) loss on plan assets (564) (730) 75 Net amortization and deferral 152 412 (351) - ------------------------------------------------------------------ Net pension cost (income) $ (46) $ (46) $ (39) ==================================================================
Of the above net pension income, $37 million in 1996, $30 million in 1995, and $29 million in 1994 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits --------------------------- 1996 1995 1994 --------------------------- (in millions) Benefits earned during the year $ 20 $ 28 $ 31 Interest cost on accumulated benefit obligation 60 67 64 Amortization of transition obligation 15 27 27 Actual (return) loss on plan assets (17) (23) 2 Net amortization and deferral 6 12 (10) - ------------------------------------------------------------------ Net postretirement costs $ 84 $111 $114 ==================================================================
Of the above net postretirement costs, $64 million in 1996, $78 million in 1995, and $77 million in 1994 were charged to operating expenses. In addition, $3 million in 1996, $11 million in 1995, and $18 million in 1994 were deferred, and the remainder 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 $85 million, $42 million, and $112 million for the years 1996, 1995, and 1994, 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 $48 million at December 31, 1996.
3. LITIGATION AND REGULATORY MATTERS
Stockholder Suit Concluded
In April 1991, two Southern Company stockholders filed a derivative action suit in the U.S. District Court for the Southern District of Georgia against certain current and former directors and officers of Southern Company. The suit alleges violations of the Federal Racketeer Influenced and Corrupt Organizations Act (RICO) by officers and breaches of fiduciary duty and gross negligence by all defendants resulting from alleged fraudulent accounting for spare parts, illegal political campaign contributions, violations of federal securities laws involving misrepresentations and omissions in SEC filings, and concealment of the foregoing acts. The complaint sought damages -- including treble damages pursuant to RICO -- in an unspecified amount, which if awarded, would have been payable to Southern Company. The court ruled the plaintiffs had failed to present adequately their allegation that Southern Company board of directors' refusal of an earlier demand by the plaintiffs was wrongful. In April 1994, the U.S. Court of Appeals for the 11th Circuit reversed the dismissal and remanded the case to the trial court, finding that allegations by the plaintiffs created a reasonable doubt that the board validly exercised its business judgment in refusing the earlier demand. In June 1995, for the second time, the trial court dismissed the suit, and the plaintiffs appealed. A panel of the court of appeals in May 1996 affirmed the trial court's dismissal. The plaintiffs' request for a rehearing was denied. This matter is now concluded.
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
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, 1996, 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. However, full recovery of Georgia Power's costs depends on the GPSC's treatment of the plant's costs and the disposition of the plant's capacity output. In June 1996, the GPSC initiated a review of this plant. In the event the GPSC does not allow full recovery of the plant costs, then the portion not allowed may have to be written off. In 1995, the plant went into commercial operation. At December 31, 1996, Georgia Power's net investment in the plant was approximately $175 million.
The final outcome of this matter cannot now be determined. Accordingly, no provision for any write-down of the investment in the plant has been made.
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 of refunds could range up to approximately $160 million at December 31, 1996. However, management believes that rates are not excessive and that refunds are not justified.
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
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.
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 an accounting order, which will be in effect for three years beginning 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 court ruled that statutory requirements applicable to rates cases were not followed and remanded the matter to the GPSC. Both the GPSC and Georgia Power appealed the court's decision to the Georgia Court of Appeals. Georgia Power is continuing to record expenses in accordance with the accounting order pending the outcome of this matter.
4. CONSTRUCTION PROGRAM
The system companies are engaged in continuous construction programs, currently estimated to total some $1.4 billion in 1997, $1.3 billion in 1998, and $1.4 billion in 1999. 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, 1996, significant purchase commitments were outstanding in connection with the construction program. The operating companies do not have any traditional baseload generating plants under construction. However, 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
Southern Company plans to issue equity capital in 1997. The amount and timing of additional equity capital to be raised in 1997 -- 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
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
long-term debt and preferred securities primarily for the purposes of debt maturities and for redeeming higher-cost securities if market conditions permit.
Bank Credit Arrangements
At the beginning of 1997, unused credit arrangements with banks totaled $4.1 billion, of which approximately $1.7 billion expires at various times during 1997 and 1998; $1.0 billion in syndicated credit arrangements expires April 19, 2001; and the remaining $1.4 billion is under revolving credit agreements.
The revolving credit agreements are as follows:
Amount of Credit ------------------------------------- Company Total Unused Expires - ------------ -------------------- ------------- (in millions)
Georgia Power $ 60 $ 49 5-01-99 Mississippi Power 40 20 12-01-99 Savannah Electric 20 15 12-31-98 Southern Company 300 300 7-01-99 Southern Company 300 300 11-30-99 Southern Energy 520 215 11-05-99 Southern Energy 283 64 Various Combined 400 400 6-30-99 - ---------------------------------------------- Total $1,923 $1,363 ==============================================
Combined unused revolving credit agreements of $400 million expiring in 1999 are with several banks that provide Southern Company, Alabama Power, and Georgia Power up to $100 million, $135 million, and $165 million, respectively, for available credit to provide liquidity support for commercial paper programs.
Most of the revolving credit 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 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.
Southern Company's $1.0 billion syndicated credit arrangement allows for revolving loans and competitive bid loans, provided that the sum of the aggregate amount of revolving loans outstanding plus the aggregate amount of competitive bid loans outstanding shall not exceed the revolving loan commitment of $1.0 billion. This agreement requires payment of commitment fees based on the unused portion of the commitments. Southern Company also pays an agent fee in connection with this arrangement.
In connection with all other lines of credit, the companies have the option of paying fees or maintaining compensating balances, which are substantially all the cash of the companies except for daily working funds and similar items. These balances are not legally restricted from withdrawal.
A portion of the $4.1 billion unused credit arrangements with banks -- discussed earlier -- is allocated to provide liquidity support to the companies' variable rate pollution control bonds. At December 31, 1996, the amount of credit lines allocated was $829 million.
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, and Georgia Power, 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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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated long-term obligations at December 31, 1996, were as follows:
Purchased Year Fuel Power - -------- --------------------------------- (in millions) 1997 $ 1,908 $ 553 1998 1,674 249 1999 1,251 162 2000 794 167 2001 748 169 2002 and thereafter 4,797 1,845 - ------------------------------------------------------------- Total commitments $11,172 $3,145 =============================================================
Operating Leases
Southern Company has operating lease agreements with various terms and expiration dates. These expenses totaled $23 million, $17 million, and $15 million, for 1996, 1995, and 1994, respectively. At December 31, 1996, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts - -------- --------------- (in millions) 1997 $ 25 1998 24 1999 25 2000 24 2001 23 2002 and thereafter 333 - ----------------------------------------------------------- Total minimum payments $454 ===========================================================
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, 1996, 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 $843 Plant Hatch (nuclear) 50.1 854 436 Plant Miller (coal) Units 1 and 2 91.8 714 296 Plant Scherer (coal) Units 1and 2 8.4 112 42 Plant Wansley (coal) 53.5 301 134 Rocky Mountain (pumped storage) 25.4 202 27 - -------------------------------------------------------------------
In 1994, Georgia Power and FPC entered into a joint ownership agreement regarding the Intercession City combustion turbine unit. The unit went into commercial operation in early 1997 and will be operated and maintained by FPC. Georgia Power has an approximate interest of 33 percent in the 150-megawatt unit, with retention of 100 percent of the capacity from June through September. FPC has the capacity the remainder of the year. Georgia Power's investment in the unit is $13 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.
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7. LONG-TERM POWER SALES AGREEMENTS
NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
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 have been as follows:
Unit Other Year Power Long-Term Total ----- --------------------------------------- (in millions) 1996 $217 $ - $217 1995 237 - 237 1994 257 19 276
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 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, 1996, the tax- related regulatory assets and liabilities were $1.3 billion and $879 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:
1996 1995 1994 ----------------------------- (in millions) Total provision for income taxes: Federal -- Currently payable $569 $567 $598 Deferred -- current year 116 184 67 -- reversal of prior years (74) (111) (75) Deferred investment tax credits - 1 - - ------------------------------------------------------------------- 611 641 590 - ------------------------------------------------------------------- State -- Currently payable 82 90 86 Deferred -- current year 23 26 15 -- reversal of prior years (9) (12) (11) - ------------------------------------------------------------------- 96 104 90 - ------------------------------------------------------------------- International 50 24 5 - ------------------------------------------------------------------- Total 757 769 685 Less income taxes charged (credited) to other income 10 (36) (26) - ------------------------------------------------------------------- Total income taxes charged to operations $747 $805 $711 ===================================================================
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:
1996 1995 ---------- ------------ (in millions) Deferred tax liabilities: Accelerated depreciation $2,981 $2,795 Property basis differences 2,154 2,175 Deferred plant costs 54 100 Other 308 247 - ------------------------------------------------------------------- Total 5,497 5,317 - ------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 110 107 Other property basis differences 253 273 Deferred costs 139 118 Pension and other benefits 68 66 Other 214 192 - ------------------------------------------------------------------- Total 784 756 - ------------------------------------------------------------------- Net deferred tax liabilities 4,713 4,561 Portion included in current assets, net 25 50 - ------------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheet $4,738 $4,611 ===================================================================
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
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 $33 million in 1996, $38 million in 1995, and $42 million in 1994. At December 31, 1996, 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:
1996 1995 1994 --------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.2 3.4 3.3 Non-deductible book depreciation 1.8 1.6 1.8 Difference in prior years' deferred and current tax rate (1.0) (1.1) (1.5) Other (0.5) 0.3 0.3 - ------------------------------------------------------------------ Effective income tax rate 38.5% 39.2% 38.9% ==================================================================
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. COMMON STOCK
Shares Reserved
At December 31, 1996, a total of 59 million shares was reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Executive Stock Option Plan.
Executive Stock Option Plan
Southern Company's Executive Stock Option Plan authorizes the granting of non-qualified stock options to key employees of Southern Company, including officers. As of December 31, 1996, 249 current and former employees participated in the plan. The maximum number of shares of common stock that may be issued under the Executive Stock Option Plan may not exceed 6 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of four years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the board of directors in accordance with the plan. Stock option activity in 1995 and 1996 is summarized below:
Shares Average Subject Option Price To Option Per Share ---------------------------------- Balance at December 31, 1994 1,736,604 $17.39 Options granted 1,161,174 21.63 Options canceled (8,088) 21.63 Options exercised (413,391) 14.34 - -------------------------------------------------------------------- Balance at December 31, 1995 2,476,299 19.87 Options granted 1,460,731 23.00 Options canceled (16,862) 22.23 Options exercised (97,988) 17.94 - -------------------------------------------------------------------- Balance at December 31, 1996 3,822,180 $21.11 ==================================================================== Shares reserved for future grants: At December 31, 1994 3,268,001 At December 31, 1995 2,114,915 At December 31, 1996 671,046 - -------------------------------------------------------------------- Options exercisable: At December 31, 1995 831,227 At December 31, 1996 1,276,846 - --------------------------------------------------------------------
The pro forma impact on net income of fair-value accounting for options granted -- as required by FASB Statement No. 123, Accounting for Stock-Based Compensation -- is not significant to the financial statements.
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 1996, consolidated retained earnings included $3.3 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 or charters.
10. PREFERRED SECURITIES
The subsidiary obligated mandatorily redeemable preferred securities were issued by special purpose financing entities. Substantially all the assets of these entities are $100 million and $335 million aggregate principal amount of Alabama Power or Georgia Power junior subordinated debt, respectively. Alabama Power and Georgia Power each considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full
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NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
and unconditional guarantee, by the respective companies of the issuing entities' payment obligations with respect to such preferred securities.
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1996 1995 -------------------- (in millions)
Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: Collateralized -- 4.375% to 9.375% due 2000-2026 $1,403 $1,466 Variable rates (3.2% to 5.25% at 1/1/97) due 2011-2025 639 639 Non-collateralized -- 7.25% due 2003 1 1 6.75% to 8.375% due 2015-2020 200 277 5.8% due 2022 10 10 Variable rates (4.65% to 5.25% at 1/1/97) due 2021-2026 265 132 - ---------------------------------------------------------------- 2,518 2,525 - ---------------------------------------------------------------- Capitalized lease obligations 151 147 - ---------------------------------------------------------------- Notes payable: 4.62% to 10% due 1996-1999 230 252 6.375% to 11% due 2000-2008 864 240 Adjustable rates (4% to 13% at 1/1/97) due 1996-1999 210 190 Adjustable rates (5.775% to 7.5625% at 1/1/97) due 2000-2002 96 938 Adjustable rate (7.38% at 1/1/97) due 2004-2006 15 111 - ---------------------------------------------------------------- 1,415 1,731 - ---------------------------------------------------------------- Total $4,084 $4,403 ================================================================
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 2001 applicable to other long-term debt are as follows: $79 million in 1997; $96 million in 1998; $279 million in 1999; $160 million in 2000; and $205 million in 2001.
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:
1996 1995 ---------------- (in millions) Bond improvement fund requirements $ 40 $ 43 Less: Portion to be satisfied by certifying property additions 4 18 - ----------------------------------------------------------------- Cash sinking fund requirements 36 25 First mortgage bond maturities and redemptions 76 220 Other long-term debt maturities (Note 11) 79 264 - ----------------------------------------------------------------- Total $191 $509 =================================================================
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 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
II-33
NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
interests -- is $159 million and $162 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 Mutual Limited (NML), 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 $9 million and $11 million, respectively, under current 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 NML coverage. This excess insurance is provided by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company.
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 21 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 $15 million and $16 million, respectively. The maximum replacement power assessments are $8 million for Alabama Power and $12 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.
Alabama Power and Georgia Power participate in an insurance program for nuclear workers that provides coverage for worker tort claims filed for bodily injury caused at commercial nuclear power plants. In the event that claims for this insurance exceed the accumulated reserve funds, Alabama Power and Georgia Power could be subject to a maximum total assessment of approximately $6 million each.
All retrospective assessments -- whether generated for liability, property, or replacement power -- may be subject to applicable state premium taxes.
II-34
NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
14. ACQUISITIONS
In 1995, Southern Energy acquired SWEB for approximately $1.8 billion. This British utility distributes electricity to some 1.3 million customers.
The acquisition has been accounted for under the purchase method of accounting. The acquisition cost exceeded the fair market value of net assets by $287 million. This amount is considered goodwill and is being amortized on a straight-line basis over 40 years. A preliminary estimate of $333 million of goodwill was originally reported and later revised in 1996.
SWEB has been included in the consolidated financial statements since September 1995. The following unaudited pro forma results of operations for the years 1995 and 1994 have been prepared assuming the acquisition of SWEB, effective January 1, 1994, and assuming 100 percent short-term debt financing. The proforma results are not necessarily indicative of the actual results that would have been realized had the acquisition occurred on the assumed date, nor are they necessarily indicative of future results. Pro forma operating results are for information purposes only and are as follows:
15. SEGMENT INFORMATION
II-35
NOTES (continued) Southern Company and Subsidiary Companies 1996 Annual Report
16. QUARTERLY FINANCIAL INFORMATION (Unaudited)
II-36
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1986 - 1996 Southern Company and Subsidiary Companies 1996 Annual Report
II-37
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1986 - 1996 Southern Company and Subsidiary Companies 1996 Annual Report
II-38A
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1986 - 1996 Southern Company and Subsidiary Companies 1996 Annual Report
II-38B
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1986 - 1996 (continued) Southern Company and Subsidiary Companies 1996 Annual Report
II-39
SELECTED CONSOLIDARED FINANCIAL AND OPERATING DATA 1986-1996 (continued) Southern Company and Subsidiary Companies 1996 Annual Report
II-40A
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATE 1986 - 1996 (continued) Southern Company and Subsidiary Companies 1996 Annual Report
II-40B
II-41
II-42A
II-42B
II-43
II-44A
II-44B
( ) Denotes use of cash. II-45
( ) Denotes use of cash. II-46A
( ) Denotes use of cash.
II-46B
II-47
II-48A
II-48B
II-49
II-50A
II-50B
II-51
II-52A
II-52B
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-53
MANAGEMENT'S REPORT Alabama Power Company 1996 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 and Chief Financial Officer
February 12, 1997
II-54
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, 1996 and 1995, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1996. 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-62 through II-79) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Birmingham, Alabama February 12, 1997
II-55
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 1996 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1996 net income after dividends on preferred stock was $371 million, representing a $10.6 million (2.9 percent) increase from the prior year. This improvement can be attributed 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.
In 1995, earnings were $361 million, representing a 1.3 percent increase from the prior year. This increase was due to an increase in retail energy sales of 4.7 percent, brought about by extreme summer weather. This improvement was partially offset by a 2.6 percent increase in operating costs.
The return on average common equity for 1996 was 13.75 percent compared to 13.61 percent in 1995, and 13.86 percent in 1994.
Revenues
Total revenues for 1996 were $3.1 billion, reflecting a 3.2 percent increase from 1995. The following table summarizes the principal factors that affected operating revenues for the past three years:
Increase (Decrease) From Prior Year ---------------------------------------- 1996 1995 1994 ---------------------------------------- (in thousands) Retail -- Change in base rates $(19,380) $ 990 $ -- Unbilled adjustment -- -- 28,000 Sales growth 61,765 18,174 45,304 Weather (29,660) 54,888 (39,964) Fuel cost recovery and other (30,846) 35,235 (84,344) --------------------------------------------------------------- Total retail (18,121) 109,287 (51,004) --------------------------------------------------------------- Sales for resale -- Non-affiliates 21,529 15,380 (9,345) Affiliates 88,890 (37,032) (17,213) --------------------------------------------------------------- Total sales for resale 110,419 (21,652) (26,558) Other operating revenues 3,703 1,997 5,095 --------------------------------------------------------------- Total operating revenues $ 96,001 $ 89,632 $(72,467) --------------------------------------------------------------- Percent change 3.2% 3.1% (2.4)% ---------------------------------------------------------------
Retail revenues of $2.5 billion in 1996 decreased $18 million (0.7 percent) from the prior year, compared with an increase of $109 million (4.6 percent) in 1995. Lower fuel cost recovery was the primary reason for the decrease in 1996 retail revenues as compared to 1995. The hot weather during the summer of 1995 and higher fuel cost recovery were the primary reasons for the increase in retail revenues over 1994. 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 and energy
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1996 Annual Report
components, as well as the components of the sales to affiliated companies, were:
1996 1995 1994 ------------------------------------------- (in thousands)
Capacity $159,488 $158,825 $165,063 Energy 315,925 209,376 222,579 ---------------------------------------------------------- Total $475,413 $368,201 $387,642 ----------------------------------------------------------
Capacity revenues from non-affiliates remained relatively constant over the past three years. Sales to affiliated companies within the Southern electric system will vary from year to year depending on demand, the availability, and the variable production cost of generating resources at each company.
Kilowatt-hour (KWH) sales for 1996 and the percent change by year were as follows:
KWH Percent Change ------------------------------------------- 1996 1996 1995 1994 ------------------------------------------- (millions)
Residential 14,594 1.5% 9.1% (1.7)% Commercial* 10,904 8.6 4.1 3.4 Industrial* 19,999 0.7 2.0 3.2 Other 193 3.1 0.5 1.1 ---------- Total retail 45,690 2.7 4.7 3.3 Sales for resale - Non-affiliates 9,491 18.0 18.8 (5.2) Affiliates 10,292 53.5 (20.5) 4.3 ---------- Total 65,473 10.5% 2.6% 2.4% - ----------------------------------------------------------------- *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 increase in 1996 retail energy sales was primarily due to the strength of business and economic conditions in the company's service area. The 1995 retail sales growth was the result of hotter-than-normal summer weather and a strong economy in the company's service territory. Assuming normal weather, sales to retail customers are projected to grow approximately 2.7 percent annually on average during 1997 through 2002.
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.
Total operating expenses of $2.4 billion for 1995 were up 2.6 percent compared with the prior year. This increase was primarily due to higher other operation expenses and increased purchased power. This was somewhat offset by decreases in fuel costs and maintenance expenses.
Fuel costs constitute the single largest expense for the company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net KWH generated were as follows:
---------------------------- 1996 1995 1994 ---------------------------- Total generation (billions of KWHs) 65 58 57 Sources of generation (percent) -- Coal 72 73 68 Nuclear 20 19 23 Hydro 8 8 9 Average cost of fuel per net KWH generated (cents) -- Coal 1.71 1.71 1.92 Nuclear 0.50 0.50 0.49
Total 1.46 1.48 1.56 - -------------------------------------------------------------- Note: Oil & Gas comprise less than 0.5% of generation.
Fuel expense increased in 1996 by $85 million or 10.8 percent. This increase can be attributed to higher generation. Fuel expense decreased in 1995 by $10 million or 1.3 percent. This decrease resulted from lower average cost of fuel consumed.
Purchased power consists primarily of purchases from the affiliates of the Southern electric system. Purchased power transactions among the company and its affiliates will vary from period to period depending on demand, the
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1996 Annual Report
availability, and the variable production cost of generating resources at each company. Total KWH purchases declined 9.3 percent from the prior year.
The increase in maintenance expenses for 1996 is due to increased nuclear expenses, primarily outage related accruals. The decrease in 1995 over 1994 reflects the establishment in 1994 of the Natural Disaster Reserve. See Note 1 to the financial statements under "Natural Disaster Reserve" for additional information.
Depreciation and amortization expense increased 5.6 percent in 1996 and 3.6 percent in 1995. These increases reflect additions to utility plant.
The company contributed $6.8 million to the Alabama Power Foundation, Inc. in 1996, which represents a decrease of $4.7 million from the previous year. The Foundation makes distributions to qualified entities which are organized exclusively for charitable, educational, literary, and scientific purposes.
The decline in net interest 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. Total net interest charges and preferred stock dividends increased 12.2 percent in 1995. This increase results from (i) interest on interim obligations which rose due to higher average interest rates on an increased average amount of short-term debt outstanding and (ii) amortization of debt discount, premium, and expense net, pursuant to such order.
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.
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.
Various federal and state initiatives designed to promote wholesale and retail competition, among other things, include proposals that would allow customers to choose their electricity provider. As the initiatives materialize, the structure of the utility industry could radically change. Certain initiatives could result in a change in the ownership and/or operation of generation and transmission facilities. Numerous issues must be resolved, including significant ones relating to transmission pricing and recovery of stranded investments. Being a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. 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.
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1996 Annual Report
new markets that evolve with the 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 addition of four combustion turbine generating units in May 1996 increased related operation and maintenance expenses and depreciation expenses. These additions are to ensure reliable service to customers during critical peak times.
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. 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.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air Act) 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 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, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1996. 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 $425 million in 1996. 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 45.3 percent in 1996, compared with 45.0 percent in 1995, and 45.9 percent in 1994.
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. Additionally, in November
II-59
MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1996 Annual Report
1996, the company issued through public authorities $21 million of pollution control revenue refunding bonds.
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. A portion of the proceeds of the January 1997 issuance will be used for the redemption of $100 million of preferred stock in February 1997.
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 $425 million for 1997, $519 million for 1998, and $622 million for 1999. The total is $1.6 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 has entered into agreements with two of its industrial customers to locate cogeneration facilities at their premises. These facilities will provide process steam to the respective customers concurrent with the production of electricity for use on the company's electric system. Each facility, which is primarily composed of a combustion turbine, will have approximately 100 megawatts of electric capacity and will serve as a base load resource for the company. These facilities are expected to be placed in service in 1999 at a total cost of approximately $90 million. In addition, significant construction of transmission and distribution facilities and upgrading of generating plants will continue.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $220 million will be required by the end of 1999 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 -- impacts 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 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.
In 1995, the Environmental Protection Agency (EPA) began issuing annual sulfur dioxide emission allowances through the allowance trading program. An emission allowance is the authority to emit one ton of sulfur dioxide during a calendar year. The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
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 $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
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1996 Annual Report
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. Therefore, the current compliance strategy could require total Phase II estimated construction expenditures of approximately $40 million, of which $30 million remains to be spent. However, 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.
An average increase of up to 1 percent in annual revenue requirements from customers could be necessary to fully recover the company's cost of compliance for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include construction expenditures, increased costs for switching to low-sulfur coal, and costs related to emission allowances.
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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: revisions to the ambient air standards for ozone and particulate matter; 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. 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
It is anticipated that the funds required will be derived from sources in form and quantity similar to those used in the past. To issue additional first mortgage bonds and preferred stock, the company must comply with certain earnings coverage requirements designated in its mortgage indenture and corporate charter. The company's coverages are at a level that would permit any necessary amount of security sales at current interest and dividend rates.
As required by the Nuclear Regulatory Commission and as ordered by the APSC, the company has established external trust funds for nuclear decommissioning costs. In 1994, the company also established an external trust fund for postretirement benefits as ordered by the APSC. The cumulative effect of funding these items over a long period will diminish internally funded capital and may require capital from other sources. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning."
II-61
STATEMENTS OF INCOME For the Years Ended December 31, 1996, 1995, and 1994 Alabama Power Company 1996 Annual Report
II-62
STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1996, 1995, and 1994 Alabama Power Company 1996 Annual Report
II-63
BALANCE SHEETS At December 31, 1996 and 1995 Alabama Power Company 1996 Annual Report
II-64
BALANCE SHEETS At December 31, 1996 and 1995 Alabama Power Company 1996 Annual Report
II-65
STATEMENTS OF CAPITALIZATION At December 31, 1996 and 1995 Alabama Power Company 1996 Annual Report
II-66
STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1996, 1995, and 1994 Alabama Power Company 1996 Annual Report
II-67
NOTES TO FINANCIAL STATEMENTS Alabama Power Company 1996 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), The Southern Development and Investment Group (Southern Development), 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 Development 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 to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to:
1996 1995 ------------------------- (in thousands) Deferred income taxes $ 410,010 $ 436,837 Premium on reacquired debt 84,149 89,967 Department of Energy assessments 37,490 40,282 Vacation pay 28,369 29,458 Work force reduction costs 45,969 48,402 Deferred income tax credits (364,792) (386,038) Natural disaster reserve (20,757) (17,959) Other, net 45,521 39,172 - ---------------------------------------------------------------- Total $ 265,959 $ 280,121 ================================================================
In the event that a portion of the company's operations is no longer subject to the provisions of Statement No. 71, the company would be required to write off related regulatory assets and liabilities. In addition, the company would be required to determine any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The company 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 1996, uncollectible accounts continued to average less than 1 percent of revenues.
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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 $64 million in 1996, $54 million in 1995, and $65 million in 1994. The company has a contract with the U.S. Department of Energy (DOE) that provides 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 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, 1996, under this law to be approximately $37 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 1996 and 3.2 percent in 1995 and 1994. 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, 1996, 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 1996 $ 18 -----------------------------------------------------------
Accumulated provisions: Balance in external trust funds $ 149 Balance in internal reserves 47 ----------------------------------------------------------- Total $ 196 ===========================================================
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.
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary
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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 1996, 7.1 percent in 1995, and 7.9 percent in 1994. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 1.1 percent in 1996, 1.7 percent in 1995 and 1.5 percent in 1994.
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, 1996 $2,367 $2,420 At December 31, 1995 $2,451 $2,577 Preferred Securities: At December 31, 1996 97 94 At December 31, 1995 - - ------------------------------------------------------------
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.
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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 "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. 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 following tables show actuarial results and assumptions for pension and postretirement insurance benefits as computed under the requirements of Statement Nos. 87 and 106, respectively. The funded status of the plans at December 31 was as follows:
Pension ------------------- 1996 1995 -------------------- (in millions)
Actuarial present value of benefit obligations: Vested benefits $ 603 $ 604 Non-vested benefits 30 25 - --------------------------------------------------------------- Accumulated benefit obligation 633 629 Additional amounts related to projected salary increases 180 173 - --------------------------------------------------------------- Projected benefit obligation 813 802 Less: Fair value of plan assets 1,334 1,256 Unrecognized net gain (413) (331) Unrecognized prior service cost 46 21 Unrecognized transition asset (40) (45) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 114 $ 99 ===============================================================
Postretirement Benefits ---------------------- 1996 1995 ---------------------- (in millions)
Actuarial present value of benefit obligation: Retirees and dependents $116 $103 Employees eligible to retire 28 31 Other employees 98 104 ----------------------------------------------------------- Accumulated benefit obligation 242 238 Less: Fair value of plan assets 108 89 Unrecognized net loss 15 23 Unrecognized transition obligation 65 72 ----------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 54 $ 54 ===========================================================
In 1995, the system companies announced a cost sharing program for postretirement benefits. The program establishes limits on amounts the company will pay to provide future retiree postretirement benefits. This change reduced the 1995 accumulated postretirement benefit obligation by approximately $41 million.
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The weighted average rates assumed in the actuarial calculations were:
1996 1995 1994 -------------------------------
Discount 7.8% 7.3% 8.0% Annual salary increase 5.3 4.8 5.5 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 9.3 percent for 1996, decreasing gradually to 5.8 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, 1996, by $20 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 ---------------------------------------------------------------- 1996 1995 1994 ------------------------------- (in millions) Benefits earned during the year $ 21.5 $ 21.2 $ 20.8 Interest cost on projected benefit obligation 59.5 54.3 51.2 Actual (return) loss on plan assets (148.9) (236.3) 23.5 Net amortization and deferral 43.8 136.9 (116.2) ---------------------------------------------------------------- Net pension cost (income) $ (24.1) $ (23.9) $ (20.7) ================================================================
Of the above net pension income, $20.3 million in 1996, $17.1 million in 1995, and $15.7 million in 1994 were recorded as credits to operating expenses, and the remainder was recorded as credits to construction and other accounts.
Postretirement Benefits -------------------- 1996 1995 1994 -------------------- (in millions)
Benefits earned during the year $ 5 $ 7 $ 8 Interest cost on accumulated benefit obligation 17 18 18 Amortization of transition obligation 4 7 6 Actual (return) loss on plan assets (7) (10) 1 Net amortization and deferral 2 5 (4) - ------------------------------------------------------------- Net postretirement costs $21 $27 $29 =============================================================
Of the above net postretirement costs recorded, $17.8 million in 1996, $22.7 million in 1995, and $23 million in 1994 were charged to operating expenses and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The company has incurred costs for work force reduction programs. The costs related to these programs were $26.7 million, $14.3 million and $8.2 million for the years 1996, 1995 and 1994, 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 $46.0 million at December 31, 1996.
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
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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.
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 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 $160 million at December 31, 1996 for Southern Company, of which the company's portion would be approximately $76 million. However, management believes that rates are not excessive, and that refunds are not justified.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $425 million in 1997, $519 million in 1998, and $622 million in 1999. 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. At December 31, 1996, significant purchase commitments were outstanding in connection with the construction program. The company has entered into agreements with two of its industrial customers to locate cogeneration facilities at their premises. These facilities will provide process steam to the respective customers concurrent with the production of electricity for use on the company's electric system. Each facility, which is primarily composed of a combustion turbine, will have approximately 100 megawatts of electric capacity and will serve as a base load resource for the company. These facilities are expected to be placed in service in 1999 at a total cost of approximately $90 million. In addition, significant construction will continue related to transmission and distribution facilities and the upgrading of generating plants.
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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 the purposes of 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's primary sources of external financing are sales of first mortgage bonds and preferred stock to the public and receipt of additional paid-in capital from Southern Company. In order to issue additional first mortgage bonds and preferred stock, the company must comply with certain earnings coverage requirements contained 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 currently 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 Southern Company and Georgia Power Company, has entered into agreements with several banks outside the service area to provide $400 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 $680 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 1997 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, 1996, 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, 1996, were as follows:
Year Amounts - ---- ------------------- (in millions) 1997 $ 808 1998 770 1999 569 2000 300 2001 317 2002 - 2013 2,594 - ------------------------------------------------ Total commitments $5,358 ================================================
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Operating Leases
The company has entered into coal rail car rental agreements with various terms and expiration dates. At December 31, 1996, estimated minimum rental commitments for noncancellable operating leases were as follows:
Amounts Year ---------------- (in millions)
1997 $ 3 1998 3 1999 3 2000 3 2001 3 2002- 2017 53 - --------------------------------------------------------- Total minimum payments $68 ==========================================================
6. JOINT OWNERSHIP AGREEMENTS
The company and Georgia Power Company own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which owns electric generating units with a total rated capacity of 1,020 megawatts, together with associated transmission facilities. The capacity of these units is sold equally to the company and Georgia Power Company under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or not SEGCO has any capacity and energy available. The company's share of expenses totaled $75 million in 1996, $71 million in 1995 and $74 million in 1994, 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, 1996, the capitalization of SEGCO consisted of $52 million of equity and $76 million of long-term debt on which the annual interest requirement is $4.7 million. SEGCO paid dividends totaling $10.1 million in 1996, $7.6 million in 1995, and $11.6 million in 1994, of which one-half of each was paid to the company. SEGCO's net income was $7.7 million, $8.1 million, and $7.2 million for 1996, 1995 and 1994, respectively.
The company's percentage ownership and investment in jointly-owned generating plants at December 31, 1996, 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 $ 90 $ 40 Plant Miller Units 1 and 2 714 296 --------------------------------------------------------
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. The agreements for non-firm capacity expired in 1994. Other 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 have been as follows:
Unit Other Year Power Long-Term Total ---------------------------------------------------------- (in millions) 1996 $151 $ - $151 1995 157 - 157 1994 152 7 159 ----------------------------------------------------------
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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 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, 1996, $128.2 million of such bonds was held by the escrow agent under the contracts.
8. INCOME TAXES
At December 31, 1996, the tax-related regulatory assets and liabilities were $410 million and $365 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:
1996 1995 1994 ------------------------------------------- (in thousands) Total provision for income taxes: Federal -- Currently payable $172,911 $166,105 $219,494 Deferred-- current year (6,309) 43,493 (48,153) reversal of prior years 18,948 (15,817) 15,932 Deferred investment tax credits - (75) (1) - ---------------------------------------------------------------------------- 185,550 193,706 187,272 - ---------------------------------------------------------------------------- State-- Currently payable 16,212 18,108 20,565 Deferred-- current year 697 5,117 (4,067) reversal of prior years 3,249 (91) 3,676 - ---------------------------------------------------------------------------- 20,158 23,134 20,174 - ---------------------------------------------------------------------------- Total 205,708 216,840 207,446 Less income taxes credited to other income (22,400) (14,142) (16,834) - ---------------------------------------------------------------------------- Total income taxes charged to operations $228,108 $230,982 $224,280 ============================================================================
The tax effects of temporary differences between the carrying amounts of
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assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
1996 1995 ------------------------------ (in millions) Deferred tax liabilities: Accelerated depreciation $ 816 $ 780 Property basis differences 466 491 Premimum on reacquired debt 31 31 Other 51 42 - ---------------------------------------------------------------------- Total 1,364 1,344 - ---------------------------------------------------------------------- Deferred tax assets: Capacity prepayments 34 35 Other deferred costs 27 26 Postretirement benefits 21 25 Unbilled revenue 15 13 Other 54 43 - ---------------------------------------------------------------------- Total 151 142 - ---------------------------------------------------------------------- Net deferred tax liabilities 1,213 1,202 Portion included in current assets (liabilities), net (35) (10) - ---------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,178 $1,192 ======================================================================
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $11 million in 1996, $12 million in 1995, and $13 million in 1994. At December 31, 1996, 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:
1996 1995 1994 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.2 2.5 2.2 Non-deductible book depreciation 1.5 1.6 1.6 Differences in prior years' deferred and current tax rates (1.6) (1.8) (2.9) Other (3.0) (1.4) (0.7) -------------------------------------------------------------- Effective income tax rate 34.1% 35.9% 35.2% ==============================================================
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.
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. A portion of the proceeds of the January 1997 issuance will be used for the redemption of $100 million of preferred stock in February 1997.
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10. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1996 1995 -------------------------- (in thousands) Obligations incurred in connection with the sale of tax-exempt pollution control revenue bonds by public authorities- Collateralized - 5.5% to 6.5 % due 2023-2024 $223,040 $223,040 Variable rates (4.15% to 5.0% at 1/1/97) due 2015-2017 89,800 89,800 Non-collateralized - 7.25% due 2003 1,000 1,000 7.4% due 2016 - 21,000 5.8% due 2022 9,800 9,800 Variable rates (4.65% to 5.1% at 1/1/97) due 2021 - 2022 152,500 131,500 - -------------------------------------------------------------- 476,140 476,140 Capitalized lease obligations 8,056 8,963 - -------------------------------------------------------------- Total $484,196 $485,103 ==============================================================
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 1997, $1.0 million in 1998, $1.2 million in 1999, $1.1 million in 2000 and $1.0 million in 2001.
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:
1996 1995 --------------------------- (in thousands) Bond improvement fund requirements $ 19,410 $20,047
First mortgage bond maturities and redemptions 391 63,750 Other long-term debt maturities (Note 10) 952 885 --------------------------------------------------------------- Total long-term debt due within one year 20,753 84,682 --------------------------------------------------------------- Preferred stock to be reacquired 100,000 - --------------------------------------------------------------- Total $120,753 $84,682 ===============================================================
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 1997 requirement of $19.4 million was satisfied by the deposit of cash in 1997, all of which was used for the redemption of outstanding first mortgage bonds. Also in early 1997, the company redeemed $391 thousand first mortgage bonds and announced the February 1997 redemption of $100 million preferred stock. The preferred stock will be redeemed with a portion of the proceeds from the January 1997 Trust II security issuance. Scheduled maturities amount to $952 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
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NOTES (continued) Alabama Power Company 1996 Annual Report
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 Mutual Limited (NML), 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 $9 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 NML coverage. This excess insurance is provided by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company.
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 21 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 $15 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.
The company participates in an insurance program for nuclear workers that provides coverage for worker tort claims filed for bodily injury caused at commercial nuclear power plants. In the event that claims for this insurance exceed the accumulated reserve funds, the company could be subject to a maximum total assessment of $6 million.
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, 1996, retained earnings of $796 million was restricted against the payment of cash dividends on common stock under terms of the mortgage indenture. Supplemental indentures in connection with future first mortgage bond issues may contain more stringent common stock dividend restrictions than those currently in effect.
14. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1996 and 1995 are as follows:
Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock ------------------- ----------------------------------------- (in thousands)
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
March 1995 $646,771 $122,949 $ 65,328 June 1995 753,053 157,685 88,926 September 1995 938,284 233,322 167,938 December 1995 686,666 111,362 38,702 ----------------------------------------------------------------
The company's business is influenced by seasonal weather conditions.
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SELECTED FINANCIAL AND OPERATING DATA Alabama Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA Alabama Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA Alabama Power Company 1996 Annual Report
II-81B
SELECTED FINANCIAL AND OPERATING DATA Alabama Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Alabama Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Alabama Power Company 1996 Annual Report
II-83A
SELECTED FINANCIAL AND OPERATING DATA (continued) Alabama Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Alabama Power Company 1996 Annual Report
II-83C
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II-85A
II-85B
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II-87A
II-87B
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II-89A
II-89B
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II-91A
II-91B
ALABAMA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1996
ALABAMA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1996 (Continued)
Preferred Stock Shares Dividend Amount Series Outstanding Rate Outstanding ---------------------------------------------------------------------- (Thousands) 1946-1952 364,000 4.20% $ 36,400 1950 100,000 4.60% 10,000 1961 80,000 4.92% 8,000 1963 50,000 4.52% 5,000 1964 60,000 4.64% 6,000 1965 50,000 4.72% 5,000 1966 70,000 5.96% 7,000 1968 50,000 6.88% 5,000 1988 500,000 Auction 50,000 1992 4,000,000 7.60% 100,000 1992 2,000,000 7.60% 50,000 1993 1,520,000 6.80% 38,000 1993 2,000,000 6.40% 50,000 1993 200 Auction 20,000 1993 2,000,000 Adjustable 50,000 ========== ======== 12,844,200 $440,400 ========== ========
SECURITIES RETIRED DURING 1996
First Mortgage Bonds Principal Interest Series Amount Rate ---------------------------------------------------------------------- (Thousands) 1991 $ 23,797 9-1/4% 1993 60,000 4-1/2% =========== $ 83,797 ===========
Pollution Control Bonds Principal Interest Series Amount Rate ---------------------------------------------------------------------- (Thousands) 1986 $ 21,000 7.40% =========== $ 21,000 ===========
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GEORGIA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Georgia Power Company 1996 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 six 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/ 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 12, 1997
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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, 1996 and 1995, 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, 1996. 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-104 through II-125) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Atlanta, Georgia February 12, 1997
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 1996 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1996 earnings 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. The Company's 1995 earnings increased 15.9 percent over 1994. Earnings for 1994 were reduced by a $55 million after-tax charge related to work force reduction programs. Excluding the charge related to 1994 work force reduction programs, earnings for 1995 increased 4.8 percent over 1994 primarily due to higher retail energy sales and lower interest charges, partially offset by higher operating expenses.
Revenues
The following table summarizes the factors impacting operating revenues for the 1994-1996 period:
Increase (Decrease) From Prior Year ----------------------------------- 1996 1995 1994 ----------------------------------- Retail - (in millions) Sales growth $ 58 $110 $ 67 Weather (25) 69 (128) Fuel cost recovery 28 66 (35) Demand-side programs (10) 36 (12) ------------------------------------------------------------------ Total retail 51 281 (108) - ------------------------------------------------------------------ Sales for resale - Non-affiliates (9) (61) (183) Affiliates (41) 16 (1) - ------------------------------------------------------------------ Total sales for resale (50) (45) (184) - ------------------------------------------------------------------ Other operating revenues 10 7 3 - ------------------------------------------------------------------ Total operating revenues $ 11 $243 ($289) - ------------------------------------------------------------------ Percent change 0.3% 5.8% (6.5)% - ------------------------------------------------------------------
Retail revenues of $4.0 billion 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. Retail revenues increased in 1995 over the prior year primarily due to the continued expansion of Georgia's economy and the hot summer of 1995. Milder-than-normal weather occurred during the summer of 1994.
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.
Revenues from sales to non-affiliated utilities decreased in both 1996 and 1995. Revenues from sales to non-affiliated 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:
1996 1995 1994 ------------------------------- (in millions) Capacity $41 $53 $ 84 Energy 43 45 82 - -------------------------------------------------------------- Total $84 $98 $166 ==============================================================
Contractual unit power sales to Florida utilities for 1996 and 1995 are down primarily due to scheduled reductions that corresponded with the sales to these utilities of portions of Plant Scherer Unit 4 in June 1995 and June 1994. The amount of capacity under these contracts declined by 75 megawatts and 155 megawatts in 1996 and 1995, respectively. In 1997, the contracted capacity will decline another 14 megawatts.
Revenues from other sales to non-affiliated utilities outside the service area in 1996 increased $14 million over the prior year due to a 74.5 percent increase in sales. Revenues for 1995 decreased by $27 million due to a 51.9 percent decrease in sales. These sales are primarily energy sales generally sold at variable cost.
Revenues from municipalities and cooperatives in Georgia decreased in 1996 primarily due to the recognition of an agreement to refund $14 million to these customers and a decrease of approximately $8 million in capacity revenues under
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1996 Annual Report
a power supply agreement with Oglethorpe Power Corporation (OPC). See Note 3 to the financial statements under "Wholesale Litigation" for additional information on the refund agreement. Beginning in September 1996, OPC decreased its purchases of capacity by 250 megawatts and has notified the Company of its intent to decrease purchases of capacity by an additional 250 megawatts in September 1997, and an additional 250 megawatts in September 1998. This decrease in revenues discussed above was partially offset by revenues from increased sales compared to the prior year due to higher demand. Sales increased in 1995 primarily due to higher summer demand resulting from the hot weather.
Revenues from 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. Sales to affiliated companies do not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 1996 and the percent change by year were as follows:
Percent Change ---------------------------- KWH 1996 1995 1994 --------- ------------------------------ (in billions) Residential 17.8 3.0% 10.4% (5.8)% Commercial 20.8 4.9 5.9 2.5 Industrial 26.2 3.6 3.9 3.0 Other 0.5 8.6 2.0 5.0 ------- Total retail 65.3 3.9 6.2 0.4 ------- Sales for resale - Non-affiliates 7.9 19.4 (17.3) (44.3) Affiliates 1.2 (56.9) (10.4) 0.9 ------- Total sales for resale 9.1 (3.0) (15.4) (36.4) ------- Total sales 74.4 3.0 2.8 (8.0) =======
Residential, commercial and industrial energy sales growth in 1996 reflected strong economic growth and an increase in sales to existing customers. The 1995 sales growth was the result of favorable weather conditions in addition to increased customers and economic growth.
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:
1996 1995 1994 -------------------------- Total generation (billions of kilowatt-hours) 63.7 64.3 62.4 Sources of generation (percent) -- Coal 74.3 73.7 74.8 Nuclear 22.4 22.6 21.9 Hydro 2.7 3.0 3.1 Oil and gas 0.6 0.7 0.2 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.55 1.67 1.67 Nuclear 0.55 0.60 0.63 Oil and gas * * * Total 1.35 1.44 1.44 - --------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.
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. Fuel expense increased 3.5 percent in 1995 because of higher generation which stemmed from greater demand.
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 areas and a decline in contractual capacity purchases from the co-owners of Plant Vogtle. Purchased power expense decreased $36 million in 1995, reflecting the declining Plant Vogtle contractual capacity purchases and decreased purchases from affiliated companies. The declines in
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1996 Annual Report
Plant Vogtle contractual capacity purchases did not have a significant impact on earnings in 1996 and 1995 since these costs are being levelized over six years under the terms of the 1991 Georgia Public Service Commission (GPSC) retail rate order. 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.
The Company has incurred expenses for separation benefits associated with its work force reduction programs. These expenses were $39 million in 1996, $11 million in 1995, and $82 million in 1994.
Other operation and maintenance (O&M) expenses, excluding the provision for separation benefits, increased 2.9 percent in 1996 primarily as a result of initiatives to reduce fossil generation materials inventory levels, an adjustment to deferred postretirement benefits to reflect changes in the retiree benefits plan, 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. Other O&M expenses increased 12.2 percent in 1995 primarily as a result of the recognition of costs associated with demand-side option programs and increased maintenance expenses. The demand-side option program costs were offset in part by increases in retail revenues. During 1995, the Company expensed an additional $58 million of demand-side option program and other related costs, as compared to 1994, of which approximately $29 million was not collected through rate riders. See Note 3 to the financial statements under "Demand-Side Conservation Programs" for additional information on the recovery of these program costs.
Depreciation and amortization increased $11 million in 1996 primarily due to accelerated depreciation of generating plant pursuant to the retail accounting order effective January 1996 discussed above, and an increase in plant-in-service. Depreciation and amortization increased $43 million in 1995 primarily due to additional plant investment, accelerated amortization of software costs, and an increase in nuclear decommissioning expenses.
Taxes other than income taxes increased 1.2 percent in 1996 and 5.2 percent in 1995, primarily reflecting higher franchise taxes paid to municipalities as a result of increased sales.
Other, net decreased $35 million in 1996 primarily due to expenses in connection with activities related to the 1996 Summer Olympic games and the completion of the sale, in June 1995, of Plant Scherer Unit 4, which resulted in an after-tax gain of approximately $12 million. An increase in charitable contributions resulted in the decrease in other income (expense), net in 1995.
Interest expense decreased $52 million (17.4 percent) and $51 million (14.6 percent) in 1996 and 1995, respectively. Dividends on preferred stock also decreased $3 million in 1996. These reductions are primarily due to the refinancing of securities. The Company refinanced or retired $510 million and $1.0 billion of securities in 1996 and 1995, respectively. The retirements included the redemption of $264 million of long-term debt with the proceeds from the 1995 and 1994 Plant Scherer Unit 4 sales.
The Company has deferred certain expenses and recorded a deferred return related to Plant Vogtle under phase-in plans. 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.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1996 Annual Report
On January 1, 1996, the Company began operating under a three-year retail accounting order. Under the order, which was approved by the GPSC on February 16, 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 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. The Company's 1996 retail return on common equity was within the 10 percent to 12.5 percent range. In November 1996, on appeal by a consumer group, the Superior Court of Fulton County (Georgia) reversed the GPSC's 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 Company and the GPSC have appealed the court's decision. The Company is continuing to recognize expenses in accordance with the accounting order while it is under appeal.
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 1997 through 1999.
The Company has entered into a four-year purchase power agreement to meet peaking needs. Beginning in 1996, the Company purchased 400 megawatts of capacity. In 1997, this amount will decline to 300 megawatts and in 1998 and 1999 to 200 megawatts. Capacity payments are projected to be $5 million in 1997 and $3 million in 1998 and 1999. The Company has also entered into a 30-year purchase power agreement whereby the Company will buy electricity during peak periods from a planned 300 megawatt cogeneration facility starting in June 1998. Capacity and fixed O&M payments are projected to be $13 million in 1998 and $15 million in 1999.
The amortization of Plant Vogtle costs deferred under phase-in plans will decline by $16 million in 1997, $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. Additionally, work force reduction programs implemented in the past three years will assist in efforts to control growth in future operating expenses.
As discussed in Note 3 to the financial statements, regulatory uncertainties exist related to the Rocky Mountain pumped storage hydroelectric plant. In the event the GPSC does not allow full recovery of the plant's costs, then the portion not allowed may have to be written off. The Company's net investment in the plant as of December 1996 is approximately $175 million.
Beginning in September 1996, OPC decreased its purchases of capacity under a power supply agreement by 250 megawatts and has notified the Company of its intent to decrease purchases of capacity by an additional 250 megawatts in September 1997, and an additional 250 megawatts in September 1998. As a result, the Company's capacity revenues declined approximately $8 million in 1996, and will decline an additional $24 million in 1997, an additional $26 million in 1998, and an additional $19 million in 1999.
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.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air Act) could affect earnings if such costs are not fully recovered. The Clean Air Act and other environmental issues are discussed later under "Environmental Issues."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1996 Annual Report
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 sales in the Southeastern power markets.
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. Various federal and state initiatives designed to promote wholesale and additional retail competition, among other things, include proposals that would allow customers to choose their electricity provider. As the initiatives materialize, the structure of the utility industry could radically change. Certain initiatives could result in a change in the ownership and/or operation of generation and transmission facilities. Numerous issues must be resolved, including significant ones relating to transmission pricing and recovery of stranded investments. Being a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. Unless the Company remains a low-cost producer and provides quialty service, the Company's retail energy sales growth could be limited, and this could significantly erode earnings.
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities, 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.
FINANCIAL CONDITION
Plant Additions
In 1996 gross utility plant additions were $428 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 1996, the Company continued to lower its financing costs by refinancing higher-cost issues. New issues during 1994 through 1996 totaled $1.6 billion and retirement or repayment of securities totaled $2.2 billion. The retirements included the redemption of $131 million and $133 million in 1995 and 1994, respectively, of first mortgage bonds with the proceeds from the Plant Scherer Unit 4 sales. Composite financing rates for long-term debt
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1996 Annual Report
and preferred stock for the years 1994 through 1996, as of year-end, were as follows:
1996 1995 1994 --------------------------------- Composite interest rate on long-term debt 6.39% 6.57% 7.14% Composite preferred stock dividend rate 6.34 6.73 7.11 - ----------------------------------------------------------------
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 - -----------------------------------------------------------------
In August 1996, Georgia Power Capital Trust I (Trust I), of which the Company owns all the common securities, issued $225 million of 7.75 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust I are $232 million aggregate principal amount of the Company's 7.75 percent Junior Subordinated Notes due June 30, 2036. In January 1997, Georgia Power Capital Trust II (Trust II), of which the Company owns all the common securities, issued $175 million of 7.60 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust II are $180 million aggregate principal amount of the Company's 7.60 percent Junior Subordinated Notes due December 31, 2036.
Liquidity and Capital Requirements
Cash provided from operations decreased by $31 million in 1996, primarily due to higher operating and maintenance expenses.
The Company estimates that construction expenditures for the years 1997 through 1999 will total $490 million, $479 million and $464 million, respectively. Investments in transmission and distribution facilities, enhancements to existing generating plants, additions of a co-owned combustion turbine generating plant, 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 $436 million during 1997 through 1999.
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 1997 through 1999, 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 $1.1 billion of unused credit arrangements with banks at the beginning of 1997. See Note 9 to the financial statements under "Bank Credit Arrangements" for additional information.
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 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 -- is having a significant impact on 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1996 Annual Report
In 1995, the Environmental Protection Agency (EPA) began issuing annual sulfur dioxide emission allowances through the allowance trading program. An emission allowance is the authority to emit one ton of sulfur dioxide during a calendar year. The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
Southern Company achieved Phase I sulfur dioxide compliance at the affected units by switching to low-sulfur coal, which has required some equipment upgrades. This compliance strategy resulted in unused emission allowances being banked for later use. Construction expenditures for Georgia Power's Phase I compliance totaled approximately $163 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. Therefore, current compliance strategy could require total Phase II estimated construction expenditures, for the Company, of approximately $29 million of which $21 million remains to be spent. However, 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.
An increase of up to 1 percent in Georgia Power's annual revenue requirements from customers could be necessary to fully recover the cost of compliance for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include construction expenditures, increased costs for switching to low-sulfur coal, and costs related to emission allowances.
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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: revisions to the ambient air quality standards for ozone and particulate matter; 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 $2 million, $8 million and $8 million, in 1996, 1995, and 1994, 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.
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NOTES TO FINANCIAL STATEMENTS Georgia Power Company 1996 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), The Southern Development and Investment Group (Southern Development), 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 Development 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 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:
1996 1995 -------------------- (in millions) -------------------- Deferred income taxes $ 818 $ 872 Deferred income tax credits (382) (410) Deferred Plant Vogtle costs 171 308 Premium on reacquired debt 167 174 Corporate building lease 51 49 Demand-side program costs 44 79 Vacation pay 40 36 Postretirement benefits 38 53 Department of Energy assessments 32 33 Inventory conversions (18) (31) Other, net 27 36 ============================================================== Total $ 988 $1,199 ==============================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related regulatory assets and liabilities. 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) Georgia Power Company 1996 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. 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 1996, 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 $78 million in 1996, $86 million in 1995, and $87 million in 1994. 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 cast 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, 1996, to be approximately $30 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 1996, 3.2 percent in 1995 and 3.1 percent in 1994. In addition, the Company recorded accelerated depreciation of electric plant of $24 million in 1996 and $6 million in 1995. The amount of such charges in the accumulated provision for depreciation is $30 million at December 31, 1996. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -- together with the cost of removal, less salvage -- is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected costs of decommissioning nuclear facilities and removal of other facilities.
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 the retirement
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NOTES (continued) Georgia Power Company 1996 Annual Report
date. The estimated costs of decommissioning -- both site study costs and ultimate costs at December 31, 1996 -- based on the Company's ownership interests -- were as follows:
Plant Plant Hatch Vogtle -------------------- Site study basis (year) 1994 1994
Decommissioning periods: Beginning year 2014 2027 Completion year 2027 2038 - ------------------------------------------------------------ (in millions) Site study costs: Radiated structures $294 $233 Non-radiated structures 41 52 ============================================================ Total $335 $285 ============================================================ (in millions) Ultimate costs: Radiated structures $781 $1,018 Non-radiated structures 111 230 - ------------------------------------------------------------ Total $892 $1,248 ============================================================
(in millions) Amount expensed in 1996 $ 11 $ 9
Accumulated provisions: Balance in external trust funds $ 79 $ 51 Balance in internal reserves 27 13 ============================================================ Total $106 $ 64 ============================================================
Significant assumptions: Inflation rate 4.4% 4.4% Trust earnings rate 6.0 6.0 - ------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the GPSC. The decommissioning costs included in cost of service are based on the higher of the costs to decommission the radioactive portions of the plants based on 1994 site studies or the NRC minimum funding requirements. 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.
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 1996, 1995 and 1994, the average AFUDC rates were 6.59 percent, 6.53 percent and 6.18 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 2.5 percent for 1996, 1995, and 1994.
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NOTES (continued) Georgia Power Company 1996 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, 1996 $3,174 $3,206 At December 31, 1995 3,378 3,487 Preferred Securities: At December 31, 1996 325 333 At December 31, 1995 100 114 - ---------------------------------------------------------------
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 1996 and 1995, the Company funded $25 million and $21 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 will be expensed each succeeding year until the costs are 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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NOTES (continued) Georgia Power Company 1996 Annual Report
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and postretirement benefits as computed under the requirements of FASB Statement Nos. 87 and 106, respectively. The funded status of the plans at December 31 was as follows:
Pension --------------------- 1996 1995 --------------------- (in millions) --------------------- Actuarial present value of benefit obligations: Vested benefits $ 806 $ 830 Non-vested benefits 52 43
- -------------------------------------------------------------- Accumulated benefit obligation 858 873 Additional amounts related to projected salary increases 314 290 - --------------------------------------------------------------- Projected benefit obligation 1,172 1,163 Less: Fair value of plan assets 1,797 1,688 Unrecognized net gain (591) (465) Unrecognized prior service cost 56 26 Unrecognized transition asset (47) (52) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 43 $ 34 ===============================================================
Postretirement Benefits --------------------- 1996 1995 --------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $217 $214 Employees eligible to retire 29 16 Other employees 184 188 - --------------------------------------------------------------- Accumulated benefit obligation 430 418 Less: Fair value of plan assets 112 81 Unrecognized net loss 50 44 Unrecognized transition obligation 157 186 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $111 $ 107 ===============================================================
In 1995, the Company announced a cost sharing program for postretirement benefits. The program establishes limits on amounts the Company will pay to provide future retiree postretirement benefits. This change reduced the 1995 accumulated postretirement benefit obligation by approximately $97 million.
The weighted average rates used in actuarial calculations were:
1996 1995 1994 - ---------------------------------------------------------------- Discount 7.8% 7.3% 8.0% Annual salary increase 5.3 4.8 5.5 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 9.3 percent for 1996, decreasing gradually to 5.8 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, 1996, by $42 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 ---------------------------- 1996 1995 1994 ---------------------------- (in millions) Benefits earned during the year $ 35 $ 33 $ 34 Interest cost on projected benefit obligation 86 78 71 Actual (return) loss on plan assets (202) (317) 35 Net amortization (deferral) 62 185 (160) - ----------------------------------------------------------------- Net pension cost $ (19) $ (21) $ (20) =================================================================
Net pension costs were negative in 1996, 1995 and 1994. Of net pension amounts recorded, $14 million in 1996 and $15 million in 1995 and 1994 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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NOTES (continued) Georgia Power Company 1996 Annual Report
Postretirement Benefits 1996 1995 1994 ------------------------- (in millions) Benefits earned during the year $ 9 $13 $15 Interest cost on accumulated benefit obligation 30 34 33 Amortization of transition obligation 9 16 15 Actual (return) loss on plan assets (6) (8) 1 Net amortization (deferral) 3 4 (3) - --------------------------------------------------------------- Net postretirement cost $45 $59 $61 ===============================================================
Of the above net postretirement benefit costs recorded, $29 million in 1996, $33 million in 1995, and $28 million in 1994 were charged to operating expenses. In addition, $3 million in 1996, $11 million in 1995, and $18 million in 1994 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 $39 million in 1996, $11 million in 1995 and $82 million in 1994. Additionally, the Company recognized $9 million in 1996, $3 million in 1995, and $8 million in 1994 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.
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 subsequently appealed the Superior Court's decision. In December 1996, the Company also filed for an appeal. The Company is continuing to recognize expenses in accordance with the accounting order while it is under appeal.
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. AFUDC accrued on the Rocky Mountain plant was not credited to income or included in the plant's cost since December 1985. In 1988, the Company and 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. However, full recovery of the Company's 25.4 percent ownership interest depends on the GPSC's treatment of the plant's costs and disposition of the plant's capacity output. In June 1996, the GPSC initiated a review of the Rocky Mountain pumped storage hydroelectric plant. In the event the GPSC does not allow full recovery of the plant's costs, then the portion not allowed may have to be written off. At December 31, 1996, the Company's net investment in the plant was approximately $175 million.
The final outcome of this matter cannot now be determined. Accordingly, no provision for any write-down of the investment in the plant has been made.
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NOTES (continued) Georgia Power Company 1996 Annual Report
Demand-Side Conservation Programs
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that rate riders previously approved by the GPSC for recovery of the Company's costs incurred in connection with demand-side conservation programs were unlawful. The Company suspended collection of the demand-side conservation costs and appealed the court's decision to the Georgia Court of Appeals. The Company deferred costs related to these programs under an accounting order approved by the GPSC until December 1994, when the Company resumed collection under the rate riders after the Georgia Court of Appeals upheld their legality. In August 1995, the GPSC ordered the Company to discontinue its current demand-side conservation programs by the end of 1995. The rate riders will remain in effect until costs deferred are collected, which is expected to be by the end of 1997.
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.
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 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 $61 million at December 31, 1996. However, management believes that rates are not excessive, and that refunds are not justified.
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, 1996, 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 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 seven electrical substations on the list at a cost of approximately $1 million. In addition, the Company has recognized approximately $16 million in expenses through December 31, 1996 for the assessment of the remaining sites on the list and the anticipated clean-up cost for 13 sites that the Company plans to remediate. The accrued costs for environmental remediation obligations are not discounted to their present value. Any cost of remediating
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NOTES (continued) Georgia Power Company 1996 Annual Report
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.
Wholesale Litigation
In July 1994, Oglethorpe Power Corporation (OPC) and the Municipal Electric Authority of Georgia (MEAG) filed a joint complaint with the FERC seeking to recover from the Company an aggregate of approximately $16.5 million in alleged partial requirements rates overcharges, plus approximately $6.3 million in interest. OPC and MEAG claimed that the Company improperly reflected in such rates costs associated with capacity that had previously been sold to Gulf States pursuant to a unit power sales contract or, alternatively, that they should be allocated a portion of the proceeds received by the Company as a result of a settlement with Gulf States of litigation arising out of such contract. In November 1996, the Company reached a settlement with OPC, MEAG and the City of Dalton to pay the parties an aggregate of $14 million. The settlement has been approved by the FERC.
In May 1996, MEAG filed a complaint with the FERC seeking termination as of December 31, 1996 of the partial requirements tariff pursuant to which the Company currently sells wholesale energy to MEAG. The complaint also sought refunds in an unspecified amount as a result of alleged overcharges by the Company under the tariff for the years 1993 through 1996. In June 1996, the Company filed a response with the FERC requesting that its partial requirements service obligation to MEAG be terminated as of the date sought by MEAG. On January 10, 1997, the Company and MEAG reached an agreement to enter into a new power supply relationship which would replace in their entirety the partial requirements tariff and the scheduling services agreement between the Company and MEAG. The agreement required the parties to formalize a new contractual relationship and within approximately 45 days file the new contract with the FERC for approval. Under the agreement, the Company does not owe MEAG any refunds for alleged overcharges for the years specified.
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 will be collected through the retail fuel cost recovery provision and recognized in income over a 36-month period beginning 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 $490 million in 1997, $479 million in 1998, and $464 million in 1999. The estimates for property additions for the three-year period include $31 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.
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NOTES (continued) Georgia Power Company 1996 Annual Report
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Total estimated long-term fossil and nuclear fuel commitments at December 31, 1996 were as follows:
Minimum Year Obligations ---------------------- (in millions) 1997 $ 833 1998 679 1999 512 2000 423 2001 358 2002 and beyond 1,722 - --------------------------------------------------------------- Total minimum obligations $ 4,527 ===============================================================
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 declining fractions of OPC's and MEAG's capacity and energy from this plant. The declining commitments were in effect during periods of up to seven years following commercial operation and ended in 1996. The commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG 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 $68 million, $76 million, and $129 million in 1996, 1995, and 1994, respectively. The current projected Plant Vogtle capacity payments are:
Year Amounts ---------------------- (in millions) 1997 $ 58 1998 60 1999 62 2000 63 2001 62 2002 and beyond 858 - --------------------------------------------------------------- Total $ 1,163 ==============================================================
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.
As discussed in Note 1, the Plant Vogtle declining capacity buyback expense is being levelized over a six-year period which began in October 1991.
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:
1996 1995 1994 --------------------------------- (in millions) Energy $47 $44 $43 Capacity 30 29 33 - -------------------------------------------------------------- Total $77 $73 $76 ============================================================== Kilowatt-hours 2,780 2,391 2,429 - --------------------------------------------------------------
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NOTES (continued) Georgia Power Company 1996 Annual Report
At December 31, 1996, the capitalization of SEGCO consisted of $52 million of equity and $76 million of long-term debt on which the annual interest requirement is $5 million.
The Company has entered into a 30-year purchase power agreement, scheduled to begin in June 1998, for electricity during peaking periods from a planned 300 megawatt cogeneration facility. Capacity and fixed operation and maintenance (O&M) payments are subject to reductions for failure to meet minimum capacity output. Estimated capacity and fixed O&M payments are as follows:
Year Amounts ---------------------- (in millions) 1998 $ 13 1999 15 2000 15 2001 15 2002 and beyond 320 - --------------------------------------------------------------- Total $ 378 ===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $11 million, $12 million, and $13 million for 1996, 1995, and 1994, respectively. At December 31, 1996, estimated minimum rental commitments for these noncancelable operating leases were as follows:
Year Amounts ---------------------- (in millions) 1997 $ 11 1998 10 1999 10 2000 10 2001 10 2002 and beyond 121 - --------------------------------------------------------------- Total $ 172 ===============================================================
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 $162 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 Mutual Limited (NML), 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 $11 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 NML coverage. This excess insurance is provided by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company.
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 21 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 $16 million for excess property damage and $12 million for replacement power.
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NOTES (continued) Georgia Power Company 1996 Annual Report
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.
The Company participates in an insurance program for nuclear workers that provides coverage for worker tort claims filed for bodily injury caused at commercial nuclear power plants. In the event that claims for this insurance exceed the accumulated reserve funds, the Company could be subject to a maximum total assessment of $6 million.
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, together with transmission facilities, 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, in 1995 the Company completed the last of four separate transactions to sell Unit 4 of Plant Scherer to Florida Power & Light Company (FP&L) and Jacksonville Electric Authority (JEA) for a total price of approximately $808 million. FP&L now owns approximately 76.4 percent of the unit, with JEA owning the remainder.
The Scherer Unit 4 transactions were as follows:
Closing Percent After-Tax Date Capacity Ownership Amount Gain - --------------------------------------------------------------- (in megawatts) (in millions)
July 1991 290 35.46% $ 291 $ 14 June 1993 258 31.44 253 18 June 1994 135 16.55 133 11 June 1995 135 16.55 131 12 - --------------------------------------------------------------- Total 818 100.00% $ 808 $ 55 ===============================================================
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 150 megawatt 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. The Company's investment in the unit is approximately $13 million.
At December 31, 1996, the Company's percentage ownership and investment (exclusive of nuclear fuel) in
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NOTES (continued) Georgia Power Company 1996 Annual Report
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) 1,630 50.1 Plant Wansley (coal) 1,779 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) - -----------------------------------------------------------------
Accumulated Facility (Type) Investment Depreciation - ---------------------------------------------------------------- (in millions) Plant Vogtle (nuclear) $3,299* $843 Plant Hatch (nuclear) 854 436 Plant Wansley (coal) 301 134 Plant Scherer (coal) Units 1 and 2 112 42 Unit 3 542 150 Plant McIntosh Common Facilities (combustion-turbine) 19 1 Rocky Mountain (pumped storage) 202 27 - ----------------------------------------------------------------
* Investment net of write-offs.
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. The Company also had agreements for non-firm sales, which expired in 1994, based on the capacity of the Southern system. 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 Unit Power Sales Non-firm Sales - ----------------------------------------------------------------- (in millions) (megawatts) (in millions) (megawatts) 1996 $ 41 173 $ - - 1995 53 248 - - 1994 75 403 9 101 - -----------------------------------------------------------------
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 173 megawatts of capacity in 1996 and is scheduled to sell approximately 159 megawatts of capacity in 1997 through 1999, and in 2000, 126 megawatts will be sold. After 2000, capacity sales will decline to approximately 103 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in 2010.
Long-term non-firm power of 200 megawatts was sold by the Southern system in 1994 to FPC, of which the Company's share was 101 megawatts, under a contract that expired at the end of 1994. Sales under these long-term non-firm power sales agreements were made from available power pool energy, and the revenues from the sales were shared by the operating affiliates.
8. INCOME TAXES
At December 31, 1996, tax-related regulatory assets were $818 million and tax-related regulatory liabilities were $382 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.
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NOTES (continued) Georgia Power Company 1996 Annual Report
Details of the federal and state income tax provisions are as follows:
1996 1995 1994 ------------------------------- Total provision for income taxes: (in millions) Federal: Currently payable $ 325 $349 $306 Deferred - Current year 70 84 86 Reversal of prior years (41) (55) (57) Deferred investment tax credits - 1 (1) - ----------------------------------------------------------------- 354 379 334 - ----------------------------------------------------------------- State: Currently payable 56 60 52 Deferred - Current year 12 15 15 Reversal of prior years (5) (8) (10) - ----------------------------------------------------------------- 63 67 57 - ----------------------------------------------------------------- Total 417 446 391 - ----------------------------------------------------------------- Less: Income taxes credited to other income (19) (3) (8) ================================================================= Total income taxes charged to operations $ 436 $449 $399 =================================================================
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
1996 1995 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $ 1,736 $1,630 Property basis differences 1,038 1,074 Deferred Plant Vogtle costs 54 100 Premium on reacquired debt 67 70 Deferred regulatory costs 21 38 Other 32 29 - ---------------------------------------------------------------- Total 2,948 2,941 - ---------------------------------------------------------------- Deferred tax assets: Other property basis differences 225 239 Federal effect of state deferred taxes 100 97 Other deferred costs 93 83 Disallowed Plant Vogtle buybacks 24 25 Accrued interest 10 13 Fuel clause overrecovered 8 6 Other 18 18 - ---------------------------------------------------------------- Total 478 481 - ---------------------------------------------------------------- Net deferred tax liabilities 2,470 2,460 Portion included in current assets 53 51 - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $ 2,523 $2,511 ================================================================
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 $17 million in 1996, $22 million in 1995, and $25 million in 1994. At December 31, 1996, 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:
1996 1995 1994 ------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 3 2 3 Difference in prior years' deferred and current tax rate (1) (1) (1) Other (1) - - - ------------------------------------------------------------- Effective income tax rate 40% 40% 41% =============================================================
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NOTES (continued) Georgia Power Company 1996 Annual Report
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's first mortgage bond indenture contains various restrictions that remain in effect as long as the bonds are outstanding. At December 31, 1996, $778 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. Supplemental indentures in connection with future first mortgage bond issues may contain more stringent restrictions than those currently in effect.
The Company's charter limits 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, is below 25 percent, and to 50 percent of such net income if such ratio is less than 20 percent. At December 31, 1996, the ratio as defined was 50.3 percent.
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. In August 1996, Georgia Power Capital Trust I (Trust I), of which the Company owns all the common securities, issued $225 million of 7.75 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust I are $232 million aggregate principal amount of the Company's 7.75 percent Junior Subordinated Notes due June 30, 2036. In January 1997, Georgia Power Capital Trust II (Trust II), of which the Company owns all the common securities, issued $175 million of 7.60 percent mandatorily redeemable preferred securities. Substantially all of the assets of Trust II are $180 million aggregate principal amount of the Company's 7.60 percent Junior Subordinated Notes due December 31, 2036.
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 Georgia Power Capital Trusts' payment obligations with respect to the preferred securities.
Georgia Power Capital, L.P., Georgia Power Capital Trust I, and Georgia Power Capital Trust II 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 $1.5 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. An aggregate of approximately $90 million of the pollution control revenue bonds is secured by a subordinated interest in specific property of the Company.
Details of pollution control bonds are as follows:
Interest Rates 1996 1995 Maturity - -------------------------------------------------------------- (in millions) 2000 4.375% $ 50 $ 50 2004-2006 5% to 6.75% 143 145 2007-2011 6.375% to 6.40% 10 20 & Variable 2016 8% - 56 2017-2021 6% to 9.375% 235 287 2022-2026 5.40% to 6.75% & Variable 1,233 1,120 - ------------------------------------------------------------- Total pollution control bonds $ 1,671 $1,678 =============================================================
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NOTES (continued) Georgia Power Company 1996 Annual Report
Bank Credit Arrangements
At the beginning of 1997, the Company had unused credit arrangements with banks totaling $1.1 billion, of which $629.4 million expires at various times during 1997, $48.7 million expires at May 1, 1999, and $400 million expires at June 30, 1999.
The $400 million expiring June 30, 1999, is under revolving credit arrangements with several banks providing the Company, Alabama Power Company, and Southern Company up to a total credit amount of $400 million. To provide liquidity support for commercial paper programs, $165 million, $135 million, and $100 million are currently dedicated to the Company, Alabama Power Company, and Southern Company, respectively. However, the allocations can be changed among the borrowers by notifying the respective banks.
During the term of the agreements expiring in 1999, short-term borrowings may 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 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.
Of the Company's total $1.1 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, 1996, were $589.7 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 1996.
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, 1996 and 1995, the Company had a capitalized lease obligation for its corporate headquarters building of $87 million with an interest rate of 8.1 percent. The lease agreement provides for payments that are minimal in early years and escalate through the first 21 years of the lease. For ratemaking purposes, the GPSC has treated the lease as an operating lease and has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes is being deferred as a cost to be recovered in the future as ordered by the GPSC. At December 31, 1996, and 1995, the interest and lease amortization deferred on the Balance Sheets are $51 million and $49 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:
1996 1995 ------------------- (in millions) First mortgage bonds $ 61 $150 Preferred stock 49 - - ---------------------------------------------------------------- Total $ 110 $150 ================================================================
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 1997 requirement was met in the first quarter of the year by depositing cash with the trustee. These funds, along with cash deposited previously with the trustee to satisfy the 1995 and 1996 improvement fund requirements, were used to redeem bonds.
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NOTES (continued) Georgia Power Company 1996 Annual Report
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 and sinking 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 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 1996 and 1995 is as follows:
Net Income After Dividends on Operating Operating Preferred Quarter Ended Revenues Income Stock - ------------------------------------------------------------------- (in millions) -------------------------------------------- March 1996 $ 1,029 $192 $ 114 June 1996 1,134 233 154 September 1996 1,311 339 256 December 1996 943 122 56
March 1995 $ 974 $207 $ 116 June 1995 1,075 230 149 September 1995 1,374 337 245 December 1995 982 177 99 - -------------------------------------------------------------------
Earnings in the fourth quarter of 1996, compared to the fourth quarter of 1995, declined primarily as a result of lower retail and wholesale revenues and initiatives to reduce fossil generation materials inventory levels.
The Company's business is influenced by seasonal weather conditions.
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II-129A
II-129B
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STATEMENTS OF INCOME Georgia Power Company
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STATEMENTS OF INCOME Georgia Power Company
II-131B
STATEMENTS OF CASH FLOWS Georgia Power Company
( ) Denotes use of cash.
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STATEMENTS OF CASH FLOWS Georgia Power Company
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STATEMENTS OF CASH FLOWS Georgia Power Company
II-133B
BALANCE SHEETS Georgia Power Company
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BALANCE SHEETS Georgia Power Company
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BALANCE SHEETS Georgia Power Company
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BALANCE SHEETS Georgia Power Company
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BALANCE SHEETS Georgia Power Company
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GEORGIA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1996
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GEORGIA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1996 (Continued)
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Substantially All of Whose Assets Are Junior Subordinated Debentures or Notes
(1) Issued by Georgia Power Capital, L.P., and guaranteed to the extent Georgia Power Capital has funds by GEORGIA. (2) Issued by Georgia Power Capital Trust I and guaranteed to the extent Georgia Power Capital Trust I has funds by GEORGIA. (3) Issued in exchange for $5.00 preferred outstanding at the time of company formation.
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GEORGIA POWER COMPANY
SECURITIES RETIRED DURING 1996
First Mortgage Bonds Principal Interest Series Amount Rate - -------------------------------------------------------------------------------- (Thousands) 1992 $ 110 8-5/8% 1993 150,000 4-3/4% 1993 21,750 7.95% 1993 16,000 7-5/8% 1993 5,000 7-3/4% 1993 5,000 7.55% 1995 13,000 7.70% ======== $210,860 ========
Pollution Control Bonds Principal Interest Series Amount Rate - ------------------------------------------------------------------------------- (Thousands) 1976 $ 1,920 6-3/4% 1977 1,940 6.40% 1978 8,060 6-3/8% 1986 56,400 8% 1991 51,345 7.25% -------- $119,665 ========
Preferred Stock Principal Dividend Series Amount Rate - -------------------------------------------------------------------------------- (Thousands) 1972 $ 75,000 $7.80 1992 972 $1.90 1992 845 $1.9875 1992 1,243 $1.9375 1992 1,088 $1.925 1991 100,000 $2.125 -------- $179,148 ========
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GULF POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Gulf Power Company 1996 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 12, 1997
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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, 1996 and 1995, 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, 1996. 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-151 through II-167) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Atlanta, Georgia February 12, 1997
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1996 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1996 net income after dividends on preferred stock was $57.8 million, an increase of $0.6 million over the prior year. This improvement is primarily attributable to higher retail revenues and lower costs related to the work force reduction program implemented last year, offset somewhat by an increase in other operating expenses.
In 1995, earnings were $57.2 million, representing an increase of $2 million compared to the prior year. Earnings in 1995 were significantly affected by higher retail revenues due to exceptionally hot summer weather and lower interest charges on long-term debt.
The return on average common equity for 1996 and 1995 was 13.27 percent.
Revenues
Operating revenues increased in 1996 and 1995 as a result of the following factors:
Increase (Decrease) From Prior Year ------------------------------------- 1996 1995 1994 ------------------------------------- (in thousands) Retail -- Sales growth $ 7,123 $ 3,647 $ 7,126 Weather (1,057) 9,749 (4,631) Regulatory cost recovery and other 5,649 22,502 8,938 - ----------------------------------------------------------------- Total retail 11,715 35,898 11,433 - ----------------------------------------------------------------- Sales for resale-- Non-affiliates 2,788 (5,698) (6,098) Affiliates (857) 1,266 (5,813) - ----------------------------------------------------------------- Total sales for resale 1,931 (4,432) (11,911) Other operating revenues 1,642 8,798 (3,851) - ----------------------------------------------------------------- Total operating revenues $15,288 $40,264 $(4,329) ================================================================= Percent change 2.5% 7.0% (0.7)% - -----------------------------------------------------------------
Retail revenues of $531 million in 1996 increased $11.7 million or 2.3 percent from last year, compared with an increase of 7.4 percent in 1995 and 2.4 percent in 1994. Residential and commercial revenues increased as a result of customer growth in 1996. This increase was partially offset by milder summer weather in 1996 compared to the hotter-than-normal summer weather of 1995.
The increase in regulatory cost recovery and other retail revenues is primarily attributable to the recovery of increased 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 $81 million in 1996, increasing $1.9 million or 2.4 percent from 1995. 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:
1996 1995 1994 ----------------------------------------- (in thousands) Capacity $25,400 $25,870 $30,926 Energy 19,804 18,598 18,456 - ------------------------------------------------------------- Total $45,204 $44,468 $49,382 =============================================================
Capacity revenues decreased in 1996 and 1995, primarily reflecting the decline in net plant investment.
Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales have little impact on earnings.
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1996 Annual Report
The increase in other operating revenues for 1996 and 1995 is primarily due to increased amounts collected to recover newly-imposed county franchise fees. These fees are included in taxes other than income taxes and thus, there is no impact on earnings. Other changes for 1996 and 1995 are primarily attributable to adjustments in the regulatory cost recovery clauses for differences between recoverable costs and the amounts actually reflected in revenues. See Notes 1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery," respectively, for further discussion.
Kilowatt-hour sales for 1996 and percent changes in sales since 1994 are reported below.
KWH Percent Change ------------ --------------------------- 1996 1996 1995 1994 ------------ --------------------------- (millions) Residential 4,160 3.6% 7.0% 1.1% Commercial 2,809 3.7 6.3 4.8 Industrial 1,808 0.7 (2.8) (9.0) Other 17 2.7 (0.1) - ------------ Total retail 8,794 3.0 4.5 (0.3) Sales for resale Non-affiliates 1,534 9.9 (1.6) (2.8) Affiliates 710 (6.5) (13.1) (15.2) ------------ Total 11,038 3.3 2.2 (2.1) ==================================================================
Retail sales increased in 1996 due to customer growth of 2.7 percent in the residential class and 4.6 percent in the commercial class. The increase in energy sales to the industrial class is a result of the Real-Time-Pricing program. The price structure of this program has successfully 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 1995, retail sales increased from the prior year due to hot summer weather and an increase in residential and commercial customers. Industrial sales were lower due to the reclassification of a major customer from the industrial to commercial class and temporary production delays of other industrial customers.
In 1996, energy sales for resale to non-affiliates increased 9.9 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
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 1995, total operating expenses increased $41.3 million or 8.5 percent from 1994 primarily due to higher fuel and purchased power expenses, maintenance expenses, and taxes other than income taxes, offset by lower depreciation and amortization expenses.
Fuel and purchased power expenses for 1996 increased $4 million or 1.8 percent from 1995. The change reflects 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. In 1995, fuel and purchased power expenses increased $30.1 million or 15.5 percent from 1994 reflecting the increase in generation due to the extreme weather conditions during the summer of 1995 and slightly higher fuel costs.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1996 1995 1994 ----------------------------- Total generation (millions of kilowatt-hours) 10,214 9,828 9,559 Sources of generation (percent) Coal 99.4 99.5 99.8 Oil and gas 0.6 0.5 0.2 Average cost of fuel per net kilowatt-hour generated (cents) Coal 1.99 2.08 2.00 Oil and gas 6.41 3.56 6.93 Total 2.02 2.09 2.01 - ------------------------------------------------------------------
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1996 Annual Report
In 1996, other operation expenses increased $1.8 million or 1.5 percent from the 1995 level. The increase is primarily attributable to an increase in administrative and general expenses including costs associated with the approved increase of the Company's annual accrual to the accumulated provision for property damage to amortize deferred storm charges and restore the account balance to a reasonable level. Higher costs related to the buyouts and renegotiation of coal supply contracts and costs associated with the Company's pro rata share of affiliated companies' workforce reduction costs were offset by a decrease in costs related to the Company's work force reduction program implemented in the prior year. In 1995, other operation expenses decreased $0.5 million due to a $9.4 million reduction in the amortization costs of coal buyouts and renegotiation of coal supply contracts. This was offset by the $7 million accrual for benefits to be provided by the Company under the work force reduction program implemented during the fourth quarter of 1995. These costs are further discussed in Notes 2 and 5 to the financial statements under "Work Force Reduction Programs" and "Fuel Commitments."
Maintenance expense in 1996 decreased $0.9 million or 1.7 percent from the prior year. This is attributable to a decrease in scheduled maintenance of production facilities. In 1995, maintenance expense increased $5.2 million or 11.2 percent from the prior year due to higher power production maintenance related to non-recurring items and higher distribution maintenance.
Depreciation and amortization expenses increased $1.5 million or 2.8 percent from 1995. This change is primarily due to an increase in depreciation expense reflecting an increase in the average investment in distribution property as a result of favorable growth in the Company's service area. In 1995, the decrease in depreciation and amortization expenses of $1.5 million was attributable to property which was fully amortized by December 1994.
Federal and state income taxes increased $3.8 million or 11 percent in 1996 primarily due to an increase in taxable income. Taxes other than income taxes increased $2.4 million or 4.9 percent primarily due to an increase in county franchise fees as mentioned previously. In 1995, other taxes increased $7.9 million or 18.9 percent primarily due to an increase in county franchise fees. Franchise fees are billed and collected from customers and have no impact on earnings.
In 1996, interest expense increased $0.9 million or 3.2 percent over the prior year. The increase is 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. Interest expense in 1995 decreased $2.5 million or 7.8 percent under the prior year. The decrease was attributable to lower interest on long-term debt reflecting a lower average principal balance outstanding and the refinancing of $42 million of pollution control bonds in December 1994.
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.
A work force reduction program was implemented in the fourth quarter of 1995. The cost of the program reduced earnings by $0.7 million in 1996 and $4.3 million in 1995. The estimated savings from this program in 1996 were $2.7 million and will be approximately $3.9 million annually beginning in 1997.
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1996 Annual Report
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 due to significant hurricane-related charges to the account during 1995. Refer to Note 1 to the financial statements under "Provision for Property Damage" for further discussion.
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. 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 wholesale 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 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 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.
Various federal and state initiatives designed to promote wholesale and retail competition, among other things, include proposals that would allow customers to choose their electricity provider. As the initiatives materialize, the structure of the utility industry could radically change. Certain initiatives could result in a change in the ownership and/or operation of generation and transmission facilities. Numerous issues must be resolved, including significant ones relating to transmission pricing and recovery of stranded investments. Being a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. 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 for the Company, beginning in 1995, which require programs to reduce 154 megawatts of summer peak demand and 65,000 KWH of sales by the year 2004. In 1995, the FPSC approved the Company's programs to accomplish these goals. 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.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air Act) 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, state of 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 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
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1996 Annual Report
regulatory assets and liabilities and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition during 1996 were gross property additions of $61.4 million and a decrease of $55.5 million in notes payable. Funds for the property additions and the net decrease in short-term notes 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 bonds and other debt and retiring higher-cost issues in 1996. The Company sold $55 million of first mortgage bonds, $33.3 million of pollution control bonds, and obtained $49.1 million of long-term bank notes. Retirements, including maturities during 1996, totaled $50.9 million of first mortgage bonds, $33.3 million of pollution control bonds, and $34.9 million of long-term bank notes. The refinancing of $33.3 million in pollution control bonds and $49.2 million in first mortgage bonds will result in savings of over $1 million annually. See the Statements of Cash Flows for further details.
Composite financing rates for the years 1994 through 1996 as of year end were as follows:
1996 1995 1994 ------------------------------ Composite interest rate on long-term debt 6.1% 6.5% 6.5% Composite preferred stock dividend rate 6.4% 6.4% 6.6% - ----------------------------------------------------------------
The decrease in the composite interest rate on long-term debt from 1995 to 1996 reflects the Company's efforts to refinance higher-cost debt. The decrease in the composite preferred stock dividend rate in 1995 was primarily due to a decrease in dividends on the Company's adjustable rate preferred stock, reflecting lower interest rates.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $142 million for the three years beginning in 1997 ($47 million in 1997, $49 million in 1998, and $46 million in 1999). 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 such generating plants under construction, and current energy demand forecasts do not indicate a need for any such facilities until well into the future. 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 $121 million will be required by the end of 1999 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 -- impacts 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.
In 1995, the Environmental Protection Agency (EPA) began issuing annual sulfur dioxide emission allowances through the allowance trading program. An emission allowance is the authority to emit one ton of sulfur dioxide during a
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1996 Annual Report
calendar year. The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
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 $310 million for Southern Company, including approximately $50 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. Therefore, current compliance strategy could require total Phase II estimated construction expenditures for Southern Company of approximately $80 million, of which $60 million remains to be spent. Phase II compliance is not expected to have a material impact on Gulf Power. However, 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.
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.
An average increase of up to 2 percent in revenue requirements from the Company's customers could be necessary to fully recover the cost of compliance for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include construction expenditures, increased costs for switching to low-sulfur coal, and costs related to emission allowances.
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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: revisions to the ambient air quality standards for ozone and particulate matter; 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.
Gulf Power must comply with other environmental laws and regulations, under which the Company could incur costs to clean up contaminated properties currently or previously owned. 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
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MANAGEMENTS'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1996 Annual Report
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, 1996, the Company had $0.8 million of cash and cash equivalents and $34.5 million of unused committed lines of credit with banks to meet its short-term cash needs. See Note 5 to the financial statements under "Bank Credit Arrangements" for additional information.
In January 1997, Gulf Power Capital Trust I, of which the Company owns all the common securities, issued $40 million of 7.625 percent mandatorily redeemable preferred securities. Substantially all of the assets of the Trust are $41 million aggregate principal amount of the Company's 7.625 percent Junior Subordinated Notes due December 31, 2036.
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, pollution control bonds, and preferred stock; 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. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.
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STATEMENTS OF INCOME For the Years Ended December 31, 1996, 1995, and 1994 Gulf Power Company 1996 Annual Report
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1996, 1995, and 1994 Gulf Power Company 1996 Annual Report
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BALANCE SHEETS At December 31, 1996 and 1995 Gulf Power Company 1996 Annual Report
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BALANCE SHEETS (continued) At December 31, 1996 and 1995 Gulf Power Company 1996 Annual Report
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STATEMENTS OF CAPITALIZATION At December 31, 1996 and 1995 Gulf Power Company 1996 Annual Report
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STATEMENTS OF CAPITALIZATION (continued) At December 31, 1996 and 1995 Gulf Power Company 1996 Annual Report
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STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1996, 1995, and 1994 Gulf Power Company 1996 Annual Report
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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 1996 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), The Southern Development and Investment Group (Southern Development), 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. 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 Development 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 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:
1996 1995 ------------------------- (in thousands) Current & deferred coal contract costs $ 29,515 $ 46,535 Deferred income taxes 28,313 29,093 Deferred loss on reacquired debt 20,386 17,015 Environmental remediation 7,577 5,789 Vacation pay 4,055 4,419 Regulatory clauses (over) under recovery, net (1,740) 632 Deferred income tax credits (64,354) (67,481) Deferred storm charges 3,275 7,502 Other, net (1,202) (1,510) - ----------------------------------------------------------------- Total $ 25,825 $ 41,994 =================================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related regulatory assets and liabilities. 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 1996 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 1996, 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 and the energy component of purchased power 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 1996 and 1995 and 3.8 percent in 1994. 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. The FPSC-approved composite rate used to calculate AFUDC was 7.27 percent for 1996, 1995, and 1994. AFUDC amounts for 1996, 1995, and 1994 were $75 thousand, $223 thousand, and $1.1 million, respectively. The decrease in 1996 and 1995 is primarily due to no long-term construction projects being implemented in 1996 and due to the completion of major construction projects at Plant Daniel at the end of 1994, respectively.
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.
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NOTES (continued) Gulf Power Company 1996 Annual Report
Financial Instruments
The carrying amounts and fair values of the Company's long-term debt are shown in the table below:
Carrying Fair Amount Value ---------------------------- (in thousands) Long-term debt At December 31, 1996 $372,852 $373,394 At December 31, 1995 $354,924 $365,305 - -------------------------------------------------------------
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 cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Provision for Injuries and Damages
The Company is subject to claims and suits arising in the ordinary course of business. As permitted by regulatory authorities, the Company provides for the uninsured costs of injuries and damages by charges to income amounting to $1.2 million annually. The expense of settling claims is charged to the provision to the extent available. The accumulated provision of $1.8 million and $1.7 million at December 31, 1996 and 1995, 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, 1996, the accumulated provision for property damage had a negative balance of $3.3 million, reflecting the remaining deferred charges for expenses relating to Hurricanes Erin and Opal during 1995. 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. The FPSC approved this amount pending the results of a study it ordered the Company to file addressing the appropriate reserve level and annual accrual amount. The required study was filed with the FPSC, and in November 1996, the FPSC reaffirmed an annual accrual of $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. Therefore, during 1996, the Company accrued $4.5 million 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 Pensions, requires use of the "projected unit credit" actuarial method for financial reporting purposes.
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NOTES (continued) Gulf Power Company 1996 Annual Report
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."
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and postretirement insurance benefits as computed under the requirements of FASB Statement Nos. 87 and 106, respectively. The funded status of the plans at December 31 was as follows:
Pension -------------------------- 1996 1995 --------------------------- (in thousands) Actuarial present value of benefit obligation: Vested benefits $ 87,245 $ 87,652 Non-vested benefits 5,101 4,284 - -------------------------------------------------------------------- Accumulated benefit obligation 92,346 91,936 Additional amounts related to projected salary increases 31,121 29,073 - -------------------------------------------------------------------- Projected benefit obligation 123,467 121,009 Less: Fair value of plan assets 191,152 180,980 Unrecognized net gain (58,900) (48,438) Unrecognized prior service cost 5,618 2,578 Unrecognized transition asset (6,485) (7,187) - -------------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 7,918 $ 6,924 ====================================================================
Postretirement Benefits --------------------------- 1996 1995 --------------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $10,478 $ 9,759 Employees eligible to retire 5,484 4,921 Other employees 17,694 17,646 - ---------------------------------------------------------------- Accumulated benefit obligation 33,656 32,326 Less: Fair value of plan assets 7,996 7,050 Unrecognized net loss 1,531 1,538 Unrecognized transition obligation 5,790 7,437 - ----------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $18,339 $16,301 ================================================================
In 1995, the Company announced a cost sharing program for postretirement benefits. The program establishes limits on amounts the Company will pay to provide future retiree postretirement benefits. This change reduced the 1995 accumulated postretirement benefit obligation by approximately $7.1 million.
The weighted average rates assumed in the actuarial calculations were:
1996 1995 1994 -------------------------------- Discount 7.8% 7.3% 8.0% Annual salary increase 5.3% 4.8% 5.5% 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 9.3 percent for 1996, decreasing gradually to 5.8 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, 1996, by $2.6 million and the aggregate of the service and interest cost components of the net retiree cost by $254 thousand.
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NOTES (continued) Gulf Power Company 1996 Annual Report
Components of the plans' net costs are shown below:
Pension ------------------------------------- 1996 1995 1994 ------------------------------------- (in thousands) Benefits earned during the year $ 3,880 $ 3,867 $ 3,775 Interest cost on projected benefit obligation 9,129 8,042 7,484 Actual (return) loss on plan assets (21,021) (33,853) 3,721 Net amortization and deferral 5,920 19,619 (17,054) - ------------------------------------------------------------------- Net pension income $ (2,092) $ (2,325) $ (2,074) ===================================================================
Of the above net pension amounts, pension income of $1.5 million in 1996, $1.8 million in 1995, and $1.5 million in 1994 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits ---------------------------------- 1996 1995 1994 --------------------------------- (in thousands) Benefits earned during the year $ 939 $1,259 $1,362 Interest cost on accumulated benefit obligation 2,330 2,520 2,535 Amortization of transition obligation 356 853 854 Actual (return) loss on plan assets (797) (1,268) 129 Net amortization and deferral 318 742 (591) - --------------------------------------------------------------------- Net postretirement cost $3,146 $4,106 $4,289 =====================================================================
Of the above net postretirement costs recorded, $2.3 million in 1996 and $3.1 million in 1995 and 1994 were charged to operating expenses, and the remainder was recorded in construction and other accounts.
Work Force Reduction Programs
The Company implemented a voluntary work force reduction program in the fourth quarter of 1995 and recorded $1.2 million in 1996 and $7 million in 1995 for the total pre-tax cost related to the program. The Company has also incurred its pro rata share for the costs of affiliated companies' programs. The costs related to these programs were $2.1 million for 1996, $1 million for 1995, and $1.3 million for 1994.
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 $160 million for Southern Company, including approximately $10 million for the Company at December 31, 1996. However, management believes that rates are not excessive and that refunds are not justified.
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NOTES (continued) Gulf Power Company 1996 Annual Report
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 1996 and 1995, the Company recorded ECRC revenues of $11.0 million and $11.8 million, respectively.
At December 31, 1996, the Company's liability for the estimated costs of environmental remediation projects for known sites was $7.6 million. These estimated costs are expected to be expended during the period 1997 to 2001. These projects have been approved by the FPSC for recovery through the ECRC discussed above. Therefore, the Company recorded $1.9 million in current assets and $5.7 million in deferred charges 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 $47 million in 1997, $49 million in 1998, and $46 million in 1999. 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, 1996, significant purchase commitments were outstanding in connection with the construction program. The Company does not have any 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, pollution control bonds, and preferred stock; bank notes; and capital contributions from Southern Company. In addition, the Company may issue additional long-term debt and preferred stock primarily for the purposes of debt maturities and redemptions of higher-cost securities.
Bank Credit Arrangements
At December 31, 1996, the Company had $5 million in revolving credit lines that expire May 31, 1997, and $41.5 million of lines of credit with banks subject to renewal June 1 of each year, of which $34.5 million remained unused. In addition, the Company has a $20.3 million unused committed line of credit 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 twelve major money center banks that total $230 million, of which $13 million was committed at December 31, 1996.
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NOTES (continued) Gulf Power Company 1996 Annual Report
Assets Subject to Lien
The Company's mortgage, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into long-term commitments for the procurement of fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Total estimated long-term obligations at December 31, 1996, were as follows:
Year Fuel ------- ---------------- (in millions) 1997 $125 1998 98 1999 79 2000 71 2001 73 2002 - 2007 481 -------------------------------------------------------- Total commitments $927 ========================================================
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 basis over a ten-year period. The remaining unamortized amount was $13.3 million at December 31, 1996.
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 $16.2 million at December 31, 1996.
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, 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 inventory was $1.7 million in 1996 and 1995 and $1.2 million in 1994. The Company's annual lease payments for 1997 through 2001 will be approximately $1.7 million and after 2001, lease payments total approximately $20.7 million. 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.
6. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel, a steam-electric generating plant located in Jackson County, Mississippi. In accordance with an operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of the plant.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant Scherer is a steam-electric generating plant located near Forsyth, Georgia. In accordance with an operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is included in the corresponding operating expense accounts in the Statements of Income.
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NOTES (continued) Gulf Power Company 1996 Annual Report
At December 31, 1996, 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 $185,742(1) $222,463 Accumulated Depreciation $54,079 $102,027 Construction Work in Progress $314 $33
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 agreements for non-firm capacity expired in 1994. The unit power sales 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, revenues from capacity sales primarily affect profitability. The Company's capacity revenues have been as follows:
Other Unit Long- Year Power Term Total - ---------- ------------------------------------- (in thousands) 1996 $25,400 $ - $25,400 1995 25,870 - 25,870 1994 29,653 1,273 30,926 - -----------------------------------------------------------
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 1996, and sales will remain at that level until the expiration of the contracts in 2010, unless reduced by FPC, FP&L and JEA after 1999.
Capacity and energy sales to FP&L, the Company's largest single customer, provided revenues of $27.2 million in 1996, $25.4 million in 1995, and $29.3 million in 1994, or 4.3 percent, 4.1 percent, and 5.1 percent of operating revenues, respectively.
8. INCOME TAXES
At December 31, 1996, the tax-related regulatory assets to be recovered from customers were $28.3 million. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. At December 31, 1996, the tax-related regulatory liabilities to be credited to customers were $64.4 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:
1996 1995 1994 ---------------------------------- (in thousands) Total provision for income taxes: Federal-- Currently payable $31,022 $29,018 $34,941 Deferred--current year 26,072 23,172 18,556 --reversal of prior years (24,780) (23,116) (24,787) - ------------------------------------------------------------------ 32,314 29,074 28,710 - ------------------------------------------------------------------ State-- Currently payable 4,394 4,778 5,907 Deferred--current year 3,904 3,313 2,549 --reversal of prior years (3,039) (2,979) (3,304) - ------------------------------------------------------------------ 5,259 5,112 5,152 - ------------------------------------------------------------------ Total 37,573 34,186 33,862 Less income taxes charged (credited) to other income (248) 121 (95) - ------------------------------------------------------------------ Total income taxes charged to operations $37,821 $34,065 $33,957 ==================================================================
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NOTES (continued) Gulf Power Company 1996 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
1996 1995 ----------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $151,664 $146,926 Property basis differences 21,028 19,976 Coal contract buyouts 3,700 3,838 Property insurance 1,248 3,039 Other 12,674 10,573 - ------------------------------------------------------------------- Total 190,314 184,352 - ------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 9,773 10,212 Postretirement benefits 5,767 5,494 Other 7,814 6,313 - ------------------------------------------------------------------- Total 23,354 22,019 - ------------------------------------------------------------------- Net deferred tax liabilities 166,960 162,333 Less current portion, net 3,103 (12) - ------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $163,857 $162,345 ===================================================================
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 $2.3 million in 1996, 1995 and 1994. At December 31, 1996, 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:
1996 1995 1994 ------------------- --------- 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) (3) (2) Other (2) (2) (2) - --------------------------------------------------------------- Effective income tax rate 37% 35% 36% ===============================================================
The Company and the other subsidiaries of Southern Company file a consolidated federal tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. 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. POLLUTION CONTROL OBLIGATIONS AND OTHER LONG-TERM DEBT
Details of pollution control obligations and other long-term debt at December 31 are as follows:
1996 1995 -------------------------- (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 $ - 6% due 2006 - 12,075 8.25% due 2017 32,000 32,000 7.125% due 2021 - 21,200 6.75% due 2022 8,930 8,930 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 - - --------------------------------------------------------------- $169,630 $169,630 - --------------------------------------------------------------- Other long-term debt: 4.69% due 1996 - 25,000 5.2125% due 1996-1998 16,823 - 6.44% due 1994-1998 7,476 12,074 Variable Rate due 1999 13,500 - Variable Rate due 1999 13,500 - - --------------------------------------------------------------- 51,299 37,074 - --------------------------------------------------------------- Total $220,929 $206,704 ===============================================================
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 bonds, the Company has authenticated and delivered to trustees 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 the agreements.
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NOTES (continued) Gulf Power Company 1996 Annual Report
The estimated annual maturities of other long-term debt are as follows: $16 million in 1997, $8.3 million in 1998, and $27 million in 1999.
10. CAPITALIZATION 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:
1996 1995 ---------------------- (in thousands) Bond improvement fund requirement $ 1,550 $ 1,750 Less: Portion to be satisfied by certifying property additions 1,550 - - --------------------------------------------------------------- Cash sinking fund requirement - 1,750 Maturities of first mortgage bonds 25,000 - Current portion of other long-term debt (Note 9) 15,972 29,598 Pollution control bond maturity - 200 Redemption of preferred stock 24,500 - - --------------------------------------------------------------- Total $65,472 $31,548 ===============================================================
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.
11. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's first mortgage bond indenture contains various common stock dividend restrictions which remain in effect as long as the bonds are outstanding. At December 31, 1996, 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 limits 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, 1996, the ratio was 47.6 percent.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1996 and 1995 are as follows:
Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock - ------------------------------------------------------------------ (in thousands) 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
March 31, 1995 $140,918 $19,503 $10,880 June 30, 1995 153,057 23,390 14,096 Sept. 30, 1995 184,251 35,187 26,588 Dec. 31, 1995 140,851 13,082 5,590 - ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.
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SELECTED FINANCIAL AND OPERATING DATA Gulf Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Gulf Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Gulf Power Company 1996 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Gulf Power Company 1996 Annual Report
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STATEMENTS OF INCOME Gulf Power Company
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STATEMENTS OF INCOME Gulf Power Company
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STATEMENTS OF INCOME Gulf Power Company
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STATEMENTS OF CASH FLOWS Gulf Power Company
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STATEMENTS OF CASH FLOWS Gulf Power Company
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STATEMENTS OF CASH FLOWS Gulf Power Company
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BALANCE SHEETS Gulf Power Company
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BALANCE SHEETS Gulf Power Company
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BALANCE SHEETS Gulf Power Company
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BALANCE SHEETS Gulf Power Company
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BALANCE SHEETS Gulf Power Company
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GULF POWER COMPANY
SECURITIES RETIRED DURING 1996
First Mortgage Bonds Principal Interest Series Amount Rate - ------------------------------------------------------------------------------ (Thousands) 1978 $ 930 9% 1991 50,000 8-3/4% ======= $50,930 =======
Pollution Control Bonds Principal Interest Series Amount Rate - ------------------------------------------------------------------------------ (Thousands) 1976 $12,075 6% 1991 21,200 7-1/8% ======= $33,275 =======
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MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Mississippi Power Company 1996 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.
Dwight H. Evans President and Chief Executive Officer
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer
February 12, 1997
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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, 1996 and 1995, 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, 1996. 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-192 through 207) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
Atlanta, Georgia February 12, 1997
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 1996 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's net income after dividends on preferred stock for 1996 was $52.7 million, an increase of 0.4 percent or $0.2 million over the corresponding amount in 1995. Earnings reflect a modest increase in energy sales, an annual retail rate decrease of $3.0 million under the Environmental Compliance Overview Plan (ECO Plan), effective in April 1996, and an annual retail rate increase of $4.5 million under the Performance Evaluation Plan (PEP), effective October 1996.
A comparison of 1995 earnings to 1994 shows an increase of $3.4 million. The increase was due to increased energy sales and an annual retail rate increase of $3.7 million under the ECO Plan, effective in May 1995.
In April 1994, retail rates increased by $7.6 million annually under the ECO Plan and wholesale rates increased by $3.6 million.
Revenues
The following table summarizes the factors impacting operating revenues for the past three years:
Increase (Decrease) from Prior Year ----------------------------------- 1996 1995 1994 ----------------------------------- (in thousands) Retail -- Change in base rates (PEP and ECO Plan) $ (402) $ 2,694 $9,314 Sales growth 11,187 4,045 9,560 Weather (5,585) 4,513 1,752 Fuel cost recovery and other (1,255) 3,806 6,594 ------------------------------------------------------------- Total retail 3,945 15,058 27,220 ------------------------------------------------------------- Sales for resale -- Non-affiliates 7,776 3,698 4,611 Affiliates 14,139 (1,847) (5,981) ------------------------------------------------------------- Total sales for resale 21,915 1,851 (1,370) Other operating revenues 1,616 482 (1,571) -------------------------------------------------------------- Total operating revenues $27,476 $17,391 $24,279 ============================================================== Percent change 5.3% 3.5% 5.1% -------------------------------------------------------------
In 1996, retail revenues were $414 million, a 1.0 percent increase above the $410 million recorded in the prior year. This change in retail revenues was due to a number of factors. These factors included modest growth in energy sales of 3.8 percent, 3.3 percent and 1.9 percent to industrial, commercial and residential customers, respectively, and changes in retail revenues due to the ECO Plan and PEP, as discussed earlier. Retail revenues in 1995 when compared to 1994 showed an increase of 3.8 percent resulting from an increase in energy sales to commercial and residential customers, an increase in the number of customers and a retail rate increase under the ECO Plan. Changes in base rates reflect 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1996 Annual Report
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 6.4 percent in 1996 and 13.1 percent in 1995 with the related revenues rising 7.1 percent and 16.7 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:
1996 1995 1994 ------------------------------------- (in thousands) Capacity $ - $ 268 $ 1,965 Energy 3,761 3,627 8,473 ========================================================== Total $3,761 $3,895 $10,438 ==========================================================
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.
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 1996 and the percent change for the last three years:
Amount Percent Change (millions of ----------- ------------------------------ kilowatt-hours) 1996 1996 1995 1994 ---------- ------------------------------ Residential 2,080 1.9% 6.2% (0.4)% Commercial 2,316 3.3 6.7 8.6 Industrial 3,960 3.8 (0.9) 6.2 Other 39 1.9 1.1 (0.5) ---------- Total retail 8,395 3.2 2.9 5.1 Sales for resale -- Non-affiliates 2,727 9.4 (2.4) 0.4 Affiliates 694 184.7 39.7 (59.2) ---------- Total 11,816 8.7% 2.2% 1.3% ================================================================
Total retail energy sales in 1996 increased over 1995 primarily due to growth in the number of customers served by the Company. Total retail energy sales in 1995, when compared to the previous year, increased due to weather influences and the improving economy within the Company's service area.
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 1996 when compared to 1995 increased 6.6 percent due to higher fuel expenses, higher maintenance expenses and higher depreciation and amortization. A comparison of 1995 to 1994 operating expenses reflects an increase that resulted from higher fuel expenses, increased other operation expenses and increased depreciation and amortization.
Fuel costs are the single largest expense for the Company. In 1996, fuel costs increased above those recorded in 1995 due to a 21.7 percent increase in generation. The increase in generation can be attributed to the higher demand for energy within the Company's service area and across the Southern electric system. Further, this increased demand for energy resulted in higher purchased power costs from non-affiliates and lower purchased power costs from the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1996 Annual Report
affiliates of the Southern electric system. A comparison of 1995 fuel expenses to 1994 fuel expenses reflects an increase in generation due to higher demand for energy.
Purchased power consists mainly of energy purchases from the affiliates of 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.
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:
1996 1995 1994 ------------------------------ Total generation (millions of kilowatt-hours) 10,180 8,368 7,408 Sources of energy supply (percent) -- Coal 70 58 56 Gas 12 15 10 Oil * * * Purchased Power 18 27 34 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.43 1.58 1.67 Gas 4.24 2.32 2.56 Oil 5.71 6.21 4.15 Total average cost of energy supply 1.56 1.53 1.55 - -------------------------------------------------------------- * Not meaningful because of minimal generation from the fuel source.
Other operation expenses in 1995 when compared to 1994, increased due to higher generation, a $2.6 million charge for emission allowance expenditures and work force reduction program costs. (See Note 2 to the financial statements under "Work Force Reduction Programs" for additional information.)
In 1996, maintenance expenses rose above the amount recorded for 1995 due to the timing of maintenance performed at Plants Daniel and Watson, as well as other projects. A comparison of 1995 maintenance expenses to 1994 reflects a decrease due to the timing of scheduled maintenance.
Depreciation and amortization in 1996, as compared to 1995, increased primarily due to additional plant investment, higher depreciation rates beginning in 1996, and increased amortization of regulatory assets. In 1995, as compared to 1994, depreciation and amortization increased primarily due to additional plant investments.
Taxes other than income taxes for 1996 increased from 1995 much like 1995 when compared to 1994, due to higher municipal franchise taxes resulting from higher retail revenues.
The decrease in 1996 income taxes when compared to 1995, is a result of lower operating income. The change in income taxes between 1995 and 1994 also reflects the change in operating income.
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. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1996 Annual Report
revenues will be affected by any changes in rates under the PEP, the Company's performance based ratemaking plan, and the ECO Plan. PEP has proven to be a stabilizing force on electric rates, with only moderate changes in rates taking place.
The ECO Plan provides for recovery of costs (including costs of capital) associated with environmental projects approved by the Mississippi Public Service Commission (MPSC), most of which are required to comply with Clean Air Act Amendments of 1990 (Clean Air Act) regulations. The ECO Plan is operated independently of PEP. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters."
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate schedules and power sales contracts that Mississippi Power has with its sales for resale customers. 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 made in Note 3 to the financial statements herein.
Future earnings in the near term will depend upon growth in energy 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 Mississippi Power's service area. However, the Energy Policy Act of 1992 (Energy Act) is beginning to have 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 its 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 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.
Various federal and state initiatives designed to promote wholesale and retail competition, among other things, include proposals that would allow customers to choose their electricity provider. As the initiatives materialize, the structure of the utility industry could radically change. Certain initiatives could result in a change in the ownership and/or operation of generation and transmission facilities. Numerous issues must be resolved, including significant ones relating to transmission pricing and recovery of stranded investments. Being a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. 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.
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, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1996 Annual Report
FINANCIAL CONDITION
Overview
The principal changes in Mississippi Power's financial condition during 1996 were gross property additions to utility plant of $61 million. Funding for gross property additions and other capital requirements have been provided from operating activities, principally earnings and the non-cash charges to income of depreciation and amortization, and other long-term debt. The Statements of Cash Flows provide additional details.
Financing Activity
Retirements, including maturities during 1996, primarily related to other long-term debt and first mortgage bonds, totaled some $100 million. In 1996, the Company obtained $80 million of long-term bank notes. (See the Statements of Cash Flows for further details.) Composite financing rates for the years 1994 through 1996 as of year-end were as follows:
1996 1995 1994 ----------------------------- Composite interest rate on long-term debt 6.03% 6.63% 6.44%
Composite preferred stock dividend rate 6.58% 6.58% 6.58% -----------------------------------------------------------
The decrease in composite interest rate on long-term debt in 1996 is primarily the result of the retirement of higher cost first mortgage bonds.
Capital Structure
At year-end 1996, the Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, was 48.9 percent, compared to 50.8 percent in 1995. The decrease in equity ratio in 1996 is attributed primarily to a 13.0 percent increase in long-term debt, excluding amounts due in one year.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $231 million ($57 million in 1997, $58 million in 1998, and $116 million in 1999). The major emphasis within the construction program will be on upgrading existing facilities and the possible addition of a combined cycle unit. 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.
Other Capital Requirements
In addition to the funds required for the Company's construction program, approximately $85.1 million will be required by the end of 1999 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 -- has significantly impacted 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.
In 1995, the Environmental Protection Agency (EPA) began issuing annual sulfur dioxide emission allowances through the allowance trading program. An emission allowance is the authority to emit one ton of sulfur dioxide during a calendar year. The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as a compliance option.
Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which has 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 $65 million for Mississippi Power.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1996 Annual Report
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as required to meet Phase II limits. Therefore, current compliance strategy for Mississippi Power could require total Phase II estimated construction expenditures of approximately $4 million, all of which remains to be spent. However, 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.
An average increase of up to 2 percent in revenue requirements from customers could be necessary to fully recover the Company's cost of compliance for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include construction expenditures, increased costs for switching to low-sulfur coal, and costs related to emission allowances.
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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: revisions to the ambient air quality standards for ozone and particulate matter; 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. 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 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 new 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1996 Annual Report
Sources of Capital
At December 31, 1996, the Company had $76.3 million of unused committed credit agreements. The Company had no short-term notes payable outstanding at year end 1996.
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.
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, pollution control obligations, and preferred stock, and the receipt of additional capital contributions from Southern Company. 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.
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NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 1996 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 The Southern Development and Investment Group (Southern Development), 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. 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. 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 Development 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 to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets as of December 31 relate to:
1996 1995 ------------------------- (in thousands) Deferred income taxes $22,274 $23,384 Vacation pay 4,806 4,715 Work force reduction costs 1,991 7,286 Deferred fuel charges - 1,546 Premium on reacquired debt 10,672 8,509 Deferred environmental costs 1,679 1,713 Property damage reserve (12,955) (12,018) Deferred income tax credits (40,568) (43,266) Other, net (2,882) (2,658) - ---------------------------------------------------------------- Total $(14,983) $ (10,789) ================================================================
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 the related regulatory assets and liabilities. In addition, the Company would be required to determine any impairment to other assets, including plant, and, if impaired, to write down the assets 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 and the energy component of purchased power. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs.
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NOTES (continued) Mississippi Power Company 1996 Annual Report
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 1996, 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 1996, and 3.2 percent in both 1995 and 1994. 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.
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 to capitalize the cost of funds devoted to construction were 7.5 percent in 1996, 8.0 percent in 1995, and 6.9 percent in 1994. AFUDC (net of income taxes), as a percent of net income after dividends on preferred stock, was 1.5 percent in 1996, 1.2 percent in 1995, and 3.5 percent in 1994.
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. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense except for the maintenance of coal cars and a portion of the railway track maintenance, which are charged to fuel stock. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Financial Instruments
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, must be disclosed. At December 31, 1996, the fair value of long-term debt was $324 million and the carrying amount was $326 million. At December 31, 1995, the fair value of long-term debt was $355 million and the carrying amount was $346 million. The fair value for long-term debt was based on either closing market price or closing price of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when used or installed.
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NOTES (continued) Mississippi Power Company 1996 Annual Report
Provision for Property Damage
Mississippi Power is self-insured for the cost of storm, fire and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by regulatory authorities, the Company provided for such costs by charges to income of $1.5 million in both 1996 and 1995 and $1.1 million in 1994. 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, 1996, the accumulated provision amounted to $13.0 million.
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. Trusts are funded 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 following tables show actuarial results and assumptions for pension and postretirement benefits as computed under the requirements of FASB Statement Nos. 87 and 106, respectively. The funded status of the plans at December 31 was as follows:
Pension ------------------------ 1996 1995 ------------------------ (in thousands) Actuarial present value of benefit obligation: Vested benefits $92,091 $91,322 Non-vested benefits 5,191 4,264 -------------------------------------------------------------- Accumulated benefit obligation 97,282 95,586 Additional amounts related to projected salary increases 30,552 28,545 -------------------------------------------------------------- Projected benefit obligation 127,834 124,131 Less: Fair value of plan assets 179,658 170,481 Unrecognized net gain (56,674) (47,034) Unrecognized prior service cost 6,422 2,868 Unrecognized transition asset (5,449) (6,001) -------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $3,877 $3,817 ==============================================================
Postretirement Benefits ------------------------ 1996 1995 ------------------------ (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $20,841 $22,575 Employees eligible to retire 2,703 1,709 Other employees 17,564 17,908 ------------------------------------------------------------ Accumulated benefit obligation 41,108 42,192 Less: Fair value of plan assets 10,210 8,700 Unrecognized net loss 1,136 4,160 Unrecognized transition obligation 5,911 7,044 -------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $23,851 $22,288 ==============================================================
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NOTES (continued) Mississippi Power Company 1996 Annual Report
In 1995, Southern Company's subsidiaries announced a cost sharing program for postretirement benefits. The program established limits on amounts the companies will pay to provide future retiree postretirement benefits. This change reduced the Company's 1995 accumulated postretirement benefit obligation by approximately $10.5 million.
The weighted average rates assumed in the above actuarial calculations were:
1996 1995 1994 --------------------------------- Discount 7.8% 7.3% 8.0% Annual salary increase 5.3 4.8 5.5 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 9.3 percent for 1996, decreasing gradually to 5.8 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, 1996, by $3.2 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 -------------------------------- 1996 1995 1994 -------------------------------- (in thousands) Benefits earned during the year $ 3,842 $ 3,636 $ 3,780 Interest cost on projected benefit obligation 9,310 8,434 7,503 Actual (return) loss on plan assets (20,438) (32,232) 3,244 Net amortization and deferral 6,442 18,650 (16,048) ============================================================== Net pension income $ (844) $ (1,512) $ (1,521) ==============================================================
Of the above net pension income, $(0.6) million in 1996, and $(1.1) million in both 1995 and 1994 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits
------------------------------ 1996 1995 1994 ------------------------------ (in thousands) Benefits earned during the year $ 958 $1,525 $1,760 Interest cost on accumulated benefit obligation 2,830 3,442 3,251 Amortization of transition obligation over 20 years 362 1,027 1,043 Actual (return) loss on plan assets (990) (1,436) 132 Net amortization and deferral 312 851 (575) ================================================================ Net postretirement costs $3,472 $5,409 $5,611 ================================================================
Of the above net postretirement costs recorded, $2.8 million in 1996, $3.9 million in 1995, and $4.4 million in 1994 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Work Force Reduction Programs
During 1994, Mississippi Power and SCS instituted work force reduction programs. The costs of the SCS work force 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 $5.3 million, $4.0 million and $3.0 million of the cost of these programs in 1996, 1995 and 1994, respectively. In 1996, Mississippi Power expensed its pro-rata share of the costs for affiliated companies' programs of $1.9 million.
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Plans
Mississippi Power's retail base rates are set under a Performance Evaluation Plan (PEP). In January 1994, the MPSC approved PEP-2. PEP-2 was designed with the MPSC objectives 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-2 includes a mechanism for sharing rate adjustments based on the Company's ability to maintain low rates for customers and on the Company's
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NOTES (continued) Mississippi Power Company 1996 Annual Report
performance as measured by three indicators that emphasize price and service to the customer. PEP-2 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-2 will remain in effect until the MPSC modifies or terminates the plan. During 1995 and 1994, there were no changes under PEP-2. In September 1996, the MPSC under PEP-2 approved a retail revenue increase of $4.5 million (1.06 percent of annual retail revenue) which became effective in October 1996.
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 $3.4 million for Mississippi Power at December 31, 1996. However, management believes that rates are not excessive, and that refunds are not justified.
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. In November 1995, the MPSC ordered a change in accounting treatment allowing emission allowance expenses to be recovered through the Company's fuel adjustment clause, and emission allowance inventory costs to be recovered through PEP-2 rather than through the ECO Plan. 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. On January 31, 1997, the Company filed with the MPSC under the ECO Plan a request for an annual retail rate increase of $0.9 million.
Mississippi Power conducts studies, when possible, to determine the extent of any required clean-up 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. 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 ECO Plan as provided in the Company's 1995 ECO order. As of December 31, 1996, the balance in the liability and regulatory asset accounts was $1.7 million, including additional feasibility study costs. 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.
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NOTES (continued) Mississippi Power Company 1996 Annual Report
4. CONSTRUCTION PROGRAM
Mississippi Power is engaged in continuous construction programs, the costs of which are currently estimated to total $57 million in 1997, $58 million in 1998, and $116 million in 1999.
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. The Company does not currently have any new generating plants under construction. However, significant construction will continue related to transmission and distribution facilities, the upgrading of generating plants, and the possible addition of a combined cycle unit.
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, 1996, Mississippi Power had total committed credit agreements with banks for $96.3 million. At year-end 1996, the unused portion of these committed credit agreements was $76.3 million. These credit agreements expire at various dates in 1997 and in 1999. 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, 1996, 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 1996 use fees collected under this agreement, net of related expenses, amounted to $3.7 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. Both of these leases, totaling 745 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 is charged to fuel inventory and allocated to fuel expense as the fuel is consumed. The lease cost charged to inventory was $1.7 million in both 1996 and 1995, and $1.2 million in 1994. The Company's annual lease payments for 1997 through 2001 will be approximately $1.7 million and after 2001, lease payments total in aggregate approximately $20.7 million. The Company has the option to purchase the 745 railcars at the greater of the termination value or the fair market value, or to renew the leases at the end of the lease term.
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.
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NOTES (continued) Mississippi Power Company 1996 Annual Report
Total estimated obligations at December 31, 1996 were as follows:
Year Fuel - -------------- -------------- (in millions) 1997 $129 1998 127 1999 91 - ------------------------------------------------------ Total commitments $347 - ------------------------------------------------------
Additional commitments for fuel will be required in the future to supply the Company's fuel needs.
Mississippi Power entered into agreements to purchase summer peaking power and options for power for the years 1996 through 2000. For June through September of 1996, the Company entered into an agreement to buy 242 megawatts of capacity and energy from another electric utility. For each June through September period of 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 June 1996, the MPSC approved Mississippi Power's request that it be allowed to earn a return on the capacity portion of these agreements.
6. JOINT OWNERSHIP AGREEMENTS
Mississippi Power and Alabama Power own as tenants in common 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, 1996, 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 500 40% $ 59,102 $ 33,010
Daniel 1,000 50% 221,211 97,910 ----------------------------------------------------------------
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
General
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. Some of these agreements (unit power sales) are firm commitments and pertain to capacity related to specific generating units. Mississippi Power's participation in firm production capacity unit power sales ended in 1989. 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 as follows:
Other Year Unit Power Long-Term Total ------------------------------------------------------------ (in thousands) 1996 $ - $ - $ - 1995 268 - 268 1994 660 1,305 1,965
8. INCOME TAXES
At December 31, 1996, the tax-related regulatory assets and liabilities were $22 million and $41 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 1996 Annual Report
Details of the federal and state income tax provisions are shown below:
1996 1995 1994 --------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $29,888 $32,546 $26,072 Deferred --current year 13,816 5,122 6,313 --reversal of prior years (14,913) (7,039) (5,161) --------------------------------------------------------------- 28,791 30,629 27,224 --------------------------------------------------------------- State -- Currently payable 3,588 3,426 3,978 Deferred --current 4,727 2,270 1,669 --reversal of prior years (3,556) (833) (1,258) --------------------------------------------------------------- 4,759 4,863 4,389 --------------------------------------------------------------- Total 33,550 35,492 31,613 Less income taxes charged to other income 932 1,006 227 --------------------------------------------------------------- Federal and state income taxes charged to operations $32,618 $34,486 $31,386 ===============================================================
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:
1996 1995 ----------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $148,667 $145,093 Basis differences 10,507 10,815 Coal contract buyouts - 145 Other 19,285 16,478 ------------------------------------------------------------- Total 178,459 172,531 ------------------------------------------------------------- Deferred tax assets: Other property basis differences 24,434 25,951 Pension and other benefits 8,750 7,356 Property insurance 4,955 4,551 Unbilled fuel 2,808 3,039 Other 11,302 7,103 ------------------------------------------------------------- Total 52,249 48,000 ------------------------------------------------------------- Net deferred tax liabilities 126,210 124,531 Portion included in current assets, net 7,227 5,180 ------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $133,437 $129,711 =============================================================
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 $1.4 million in 1996, and $1.5 million in 1995 and 1994. At December 31, 1996, 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:
1996 1995 1994 ----------------------------- Total effective tax rate 37% 38% 37% State income tax, net of federal income tax benefit (3) (3) (3)% Tax rate differential 1 - 1 ------------------------------------------------------------- Statutory federal tax rate 35% 35% 35% =============================================================
Mississippi Power and the subsidiaries of Southern Company file a consolidated federal income tax return. Under a joint consolidated income tax
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NOTES (continued) Mississippi Power Company 1996 Annual Report
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. OTHER LONG-TERM DEBT
Details of pollution control obligations and other long-term debt are as follows:
December 31, 1996 1995 --------------------- (in thousands) Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: 5.80% due 2007 $ 960 $ 970 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 - --------------------------------------------------------------- 73,735 73,745 - --------------------------------------------------------------- Other long-term debt: Variable rates due 1996 - 55,000 Variable rates (5.80797% to 5.88906% at 1/1/97) due 1999 50,000 - Variable rate due 2000 30,000 - - --------------------------------------------------------------- 80,000 55,000 - --------------------------------------------------------------- Total $153,735 $128,745 ===============================================================
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 $10 thousand for 1997 and $20 thousand annually in 1998, 1999, 2000 and 2001.
10. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year is as follows:
1996 1995 -------------------- (in thousands) Bond improvement fund requirements $1,750 $ 2,219
Less: Portion to be satisfied by certifying property additions 1,750 - ------------------------------------------------------------- Cash improvement fund requirements - 2,219 Pollution control bond cash sinking fund requirements (Note 9) 10 10 Current portion of notes payable (Note 9) - 55,000 ============================================================= Total $ 10 $57,229 =============================================================
The first mortgage bond improvement fund requirement is one percent of each outstanding series authenticated under the indenture of Mississippi Power prior to January 1 of each year, other than first mortgage bonds issued as collateral security for certain pollution control obligations. The requirement must be satisfied by June 1 of each year by depositing cash or reacquiring bonds, or by pledging additional property equal to 166-2/3 percent of such requirement.
11. COMMON STOCK DIVIDEND RESTRICTIONS
Mississippi Power's first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 1996, 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 1996 Annual Report
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1996 and 1995 are as follows:
Net Income After Dividends Quarter Operating Operating On Ended Revenues Income Preferred Stock -------------------------------------------------------------------
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
March 1995 $109,572 $15,729 $ 9,269 June 1995 128,504 22,193 14,737 September 1995 157,119 28,517 22,161 December 1995 121,358 12,171 6,364
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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STATEMENTS OF INCOME Mississippi Power Company
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STATEMENTS OF CASH FLOWS Mississippi Power Company
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STATEMENTS OF CASH FLOWS Mississippi Power Company
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STATEMENTS OF CASH FLOWS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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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 OUTSTANDING SECURITIES AT DECEMBER 31, 1996
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MISSISSIPPI POWER COMPANY
SECURITIES RETIRED DURING 1996
First Mortgage Bonds Principal Interest Series Amount Rate - ------------------------------------------------------------------------ (Thousands) 1991 45,447 9-1/4%
Pollution Control Bonds Principal Interest Series Amount Rate - ------------------------------------------------------------------------ (Thousands) 1977 10 5.80%
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SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Savannah Electric and Power Company 1996 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 three 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/ Arthur M. Gignilliat, Jr. Arthur M. Gignilliat, Jr. President and Chief Executive Officer
/s/ K. R. Willis K. R. Willis Vice-President Treasurer and Chief Financial Officer
February 12, 1997
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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, 1996 and 1995, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1996. 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-230 through II-242) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Atlanta, Georgia February 12, 1997
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 1996 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 1996 totaled $23.9 million, representing a $0.5 million increase over the prior year. This 2.3 percent improvement in earnings over 1995 is principally the result of increased retail energy sales primarily attributable to an increase in the number of customers served.
In 1995, earnings were $23.4 million, representing a $1.3 million (5.8 percent) increase from the prior year. This was primarily due to higher retail energy sales as a result of exceptionally hot summer weather.
Revenues
Total revenues for 1996 were $234.1 million, reflecting a 3.7 percent increase compared to 1995. The following table summarizes revenue increases and decreases compared to prior years:
Increase (Decrease) From Prior Year -------------------------------------- 1996 1995 1994 -------------------------------------- Retail -- (in thousands) Sales growth $ 3,679 $ 1,068 $ 7,884 Weather (2,813) 6,232 (6,589) Fuel cost recovery and other 12,365 6,177 (9,214) ------------------------------------------------------------------- Total retail 13,231 13,477 (7,919) ------------------------------------------------------------------- Sales for resale-- Non-affiliates 147 (2,935) (1,235) Affiliates (4,070) 754 4,013 ------------------------------------------------------------------- Total sales for resale (3,923) (2,181) 2,778 ------------------------------------------------------------------- Other operating revenues (963) 2,648 (1,516) ------------------------------------------------------------------- Total operating revenues $ 8,345 $13,944 $(6,657) =================================================================== Percent change 3.7% 6.6% (3.0)% -------------------------------------------------------------------
Retail revenues increased 6.2 percent in 1996, compared to an increase of 6.7 percent in 1995. The increase in 1996 retail revenues is 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. Under the Company's fuel cost recovery provisions, fuel revenues--including purchased energy--generally equal fuel expense and have no effect on earnings. The $1.0 million decrease in other operating revenues reflects the elimination of the demand-side management rider in 1995. Revenues from demand-side management riders (included in retail revenues) recovered demand-side management program costs and had little impact on earnings. See Note 3 to the financial statements for further information on the Company's demand-side management programs.
The increase in 1995 retail revenues was attributable to hot summer weather, an increase in the number of customers served, higher demand in the industrial sector, and an increase in fuel cost recovery revenues.
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 continued to decrease in 1996 primarily as a result of the scheduled decline in megawatts of capacity under contract. The capacity and energy components were as follows:
1996 1995 1994 --------------------------------- (in thousands) Capacity $ 2 $ 3 $ 448 Energy 1,329 1,250 3,052 - ------------------------------------------------------ Total $1,331 $1,253 $3,500 ======================================================
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1996 Annual Report
Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1996 and the percent change by year were as follows:
KWH Percent Change ------------ --------------------------- 1996 1996 1995 1994 ------------ --------------------------- (millions) Residential 1,457 3.9% 8.0% (2.3)% Commercial 1,141 3.8 5.1 2.9 Industrial 839 (5.5) 11.0 (6.4) Other 126 0.1 5.4 3.1 ------------ Total retail 3,563 1.4 7.7 (1.6) Sales for resale Non-affiliates 91 4.4 (56.5) (18.4) Affiliates 42 (34.4) (31.5) 23.4 ------------ Total 3,696 0.8% 3.1% (2.2)% ==================================================================
Expenses
Total operating expenses for 1996 were $195.2 million, reflecting an $7.7 million increase over 1995. Major components of this increase include $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.
In 1995, total operating expenses were $187.5 million, reflecting an $11.8 million increase from 1994. This increase includes $6.8 million in fuel, $3.6 million in other operation, $1.1 million in maintenance, and $1.1 million in depreciation and amortization, partially offset by a $2.6 million reduction in purchased power from affiliates. The increase in fuel expense was primarily attributable to the exceptionally hot summer weather, which not only increased generation but also necessitated greater use of more costly gas-fired sources of generation. The increase in other operation expense was due to increased expenses related to demand-side management programs and employee incentive compensation programs. The increase in maintenance expense reflects maintenance performed at Plants Kraft and McIntosh during 1995, and the increase in depreciation and amortization reflects the completion in 1994 of two combustion turbine units.
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:
1996 1995 1994 -------------------------- Total energy supply (millions of kilowatt-hours) 3,917 3,908 3,768 Sources of energy supply (percent) -- Coal 28 24 18 Oil - - 1 Gas 3 6 1 Purchased Power 69 70 80 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.76 1.77 2.19 Oil 5.79 5.14 3.89 Gas 8.89 3.76 5.19 Average cost of purchased power per net kilowatt- hour (cents) 2.25 2.02 1.92 Total average cost of energy supply 2.30 2.07 2.02 ---------------------------------------------------------------
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in 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 1996 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.
Future earnings in the near term will depend upon growth in energy sales, which is subject to a number of factors. Traditionally, these factors 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 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.
Various federal and state initiatives designed to promote wholesale and retail competition, among other things, include proposals that would allow customers to choose their electricity provider. As the initiatives materialize, the structure of the utility industry could radically change. Certain initiatives could result in a change in the ownership and/or operation of generation and transmission facilities. Numerous issues must be resolved, including significant ones relating to transmission pricing and recovery of stranded investments. Being a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. 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 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 and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air Act) could affect earnings if such costs are not fully recovered. The Clean Air Act is discussed later under "Environmental Matters."
Rates to retail customers served by the Company are regulated by the Georgia Public Service Commission (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.
In August 1995, the GPSC ordered the phase out of the Company's demand-side management programs effective December 31, 1995 and the elimination of demand-side management rate riders effective October 1, 1995. In June 1996, the Company refunded to customers approximately $0.3 million which had been overcollected from the rate riders.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1996 was the addition of $29 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1996 Annual Report
Capital Structure
As of December 31, 1996, the Company's capital structure consisted of 46.7 percent common equity, 9.5 percent preferred stock and 43.8 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 May 1996, the Company issued $20 million of 6.90% first mortgage bonds maturing in 2006 and $10 million of 6.88% term notes maturing in 2001. Maturities and retirements of long-term debt were $29 million in 1996, $29 million in 1995 and $5 million in 1994.
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.
The composite interest rates and dividend rate for the years 1994 through 1996 as of year-end were as follows:
1996 1995 1994 ------------------------------- Composite interest rates on long-term debt 7.0% 7.5% 8.0% 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 A+ Preferred Stock "a2" A - -----------------------------------------------------------------
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $72 million ($26 million in 1997, $22 million in 1998, and $24 million in 1999). 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 $21.6 million will be needed by the end of 1999 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--impacts 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.
In 1995, the Environmental Protection Agency (EPA) began issuing annual sulfur dioxide emission allowances through the allowance trading program. An emission allowance is the authority to emit one ton of sulfur dioxide during a calendar year. The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1996 Annual Report
For Phase II sulfur dioxide compliance, Southern Company could use emission allowances, increase fuel switching, and/or install flue gas desulfurization equipment at selected plants. Also, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as required to meet Phase II limits. Therefore, current compliance strategy could require total Phase II estimated construction expenditures of approximately $4 million for the Company. However, 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.
An increase of up to 1 percent in annual revenue requirements from customers could be necessary to fully recover the Company's cost of compliance for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include construction expenditures, increased costs for switching to low-sulfur coal, and costs related to emission allowances.
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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various matters including: revisions to the ambient air quality standards for ozone and particulate matter; 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 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, 1996, the Company had $5.2 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, 1998, 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, $15 million remained unused at December 31, 1996.
It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived from operations and the sale of additional first mortgage bonds and preferred stock and capital contributions from Southern Company. 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.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1996, 1995, and 1994 Savannah Electric and Power Company 1996 Annual Report
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BALANCE SHEETS At December 31, 1996 and 1995 Savannah Electric and Power Company 1996 Annual Report
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NOTES (continued) Savannah Electric and Power Company 1996 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), The Southern Development and Investment Group (Southern Development) 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) 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. Southern Energy designs, builds, owns, and operates power production and delivery facilities and provides a broad range of technical services to industrial companies and utilities in the United States and a number of international markets. Southern Nuclear provides services to Southern Company's nuclear power plants. Southern Development 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 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 to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to:
1996 1995 --------------------------- (in thousands) Deferred income taxes $ 19,167 $ 21,557 Premium on reacquired debt 7,142 5,316 Deferred income tax credits (22,792) (24,419) - --------------------------------------------------------------- Total $ 3,517 $ 2,454 ===============================================================
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related regulatory assets and liabilities. In addition, the Company would be required to determine any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The Company 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 purchased power capacity 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 1996, uncollectible accounts continued to average less than 1 percent of revenues.
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NOTES (continued) Savannah Electric and Power Company 1996 Annual Report
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 2.8 percent in 1996 and 2.9 percent in 1995 and 1994. 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 8.69 percent in 1996, 7.42 percent in 1995 and 8.04 percent in 1994.
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) 1996 $155 $161 1995 154 165 - --------------------------------------------------------------
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 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.
Storm Damage Reserve
In December 1995, in response to a request by the Company, the GPSC issued an order allowing the Company to establish a Storm Damage Reserve. As of December 31, 1996, the accumulated provision amounted to $0.9 million. Regulatory treatment by the GPSC allows the Company to accrue up to an additional $0.6 million per year.
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NOTES (continued) Savannah Electric and Power Company 1996 Annual Report
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 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 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. Trusts are funded 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 debt and equity securities and money market funds.
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 following tables show actuarial results and assumptions for pension and postretirement benefits as computed under the requirements of FASB Statement Nos. 87 and 106, respectively. The funded status of the plans at December 31 was as follows:
Pension ------------------------ 1996 1995 ------------------------ (in thousands) Actuarial present value of benefit obligation: Vested benefits $39,270 $38,169 Non-vested benefits 2,939 2,585 - ---------------------------------------------------------------- Accumulated benefit obligation 42,209 40,754 Additional amounts related to projected salary increases 7,705 7,786 - ---------------------------------------------------------------- Projected benefit obligation 49,914 48,540 Less: Fair value of plan assets 42,430 36,836 Unrecognized net loss 7,252 9,606 Unrecognized prior service cost 1,240 1,375 Unrecognized net transition obligation 444 532 Adjustment required to recognize additional minimum liability - 3,727 - ---------------------------------------------------------------- (Prepaid asset) accrued liability recognized in the Balance Sheets $(1,452) $ 3,918 ================================================================
The weighted average rates assumed in the actuarial calculations for the pension plan were:
1996 1995 1994 ------------------------ Discount 7.25% 7.25% 8.00% Annual salary increase 4.75 4.75 5.25 Long-term return on plan assets 8.75 8.75 9.00 ---------------------------------------------------------------
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NOTES (continued) Savannah Electric and Power Company 1996 Annual Report
In accordance with Statement No. 87, an additional liability related to an under-funded accumulated benefit obligations was reflected at December 31, 1995. A corresponding net-of-tax balance of $0.1 million was recognized as a separate component of Common Stock Equity in the 1995 Statement of Capitalization.
Postretirement Benefits ------------------------ 1996 1995 ------------------------ (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $12,442 $13,560 Employees eligible to retire 1,614 1,471 Other employees 6,464 5,966 - ------------------------------------------------------------- Accumulated benefit obligation 20,520 20,997 Less: Fair value of plan assets 2,473 1,443 Unrecognized net loss 4,835 5,719 Unrecognized transition obligation 7,900 9,135 - ------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 5,312 $ 4,700 =============================================================
In 1995, the Company announced a cost sharing program for postretirement benefits. The program establishes limits on amounts the Company will pay to provide future retiree postretirement benefits. This change reduced the 1995 accumulated postretirement benefit obligation by approximately $3.1 million.
The weighted average rates assumed in the actuarial calculations for the postretirement benefit plans were:
1996 1995 ------------------- Discount 7.75% 7.25% Long-term return on plan assets 8.50 8.50 - ------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 9.3 percent for 1996, decreasing gradually to 5.8 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, 1996, by $1.2 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 ------------------------------ 1996 1995 1994 ------------------------------ (in thousands) Benefits earned during the year $1,352 $1,188 $1,192 Interest cost on projected benefit obligation 3,389 3,395 3,279 Actual (return) loss on plan assets (4,852) (5,791) 27 Net amortization and deferral 2,439 4,125 (1,474) - -------------------------------------------------------------------- Net pension cost $2,328 $2,917 $3,024 ====================================================================
Of the above net pension costs, $2.0 million in 1996, $2.4 million in 1995 and $2.6 million in 1994 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits ------------------------------ 1996 1995 1994 ------------------------------ (in thousands) Benefits earned during the year $ 360 $ 504 $ 632 Interest cost on accumulated benefit obligation 1,422 1,638 1,492 Amortization of transition obligation 494 723 723 Actual (return) loss on plan assets (145) (34) 6 Net amortization and deferral 187 93 111 - -------------------------------------------------------------------- Net postretirement costs $2,318 $2,924 $2,964 - --------------------------------------------------------------------
Of the above net postretirement costs, $2.0 million in 1996, $2.4 million in 1995 and $2.4 million in 1994 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
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NOTES (continued) Savannah Electric and Power Company 1996 Annual Report
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 1996, 1995 and 1994.
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.
In August 1995, the GPSC ordered the phase out of the Company's demand-side management programs effective December 31, 1995 and the elimination of demand-side management rate riders effective October 1, 1995. In June 1996, the Company refunded to customers approximately $0.3 million which had been overcollected from the rate rider.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently estimated to total $26 million in 1997, $22 million in 1998 and $24 million in 1999. 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 1996, unused credit arrangements with five banks totaled $20.5 million and expire at various times during 1997.
The Company's revolving credit arrangements of $20 million, of which $15 million remained unused as of December 31, 1996, expire December 31, 1998. These agreements allow short-term borrowings to be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at the Company's option.
In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments.
Assets Subject to Lien
As amended and supplemented, the Company's Indenture of Mortgage, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises. A second lien for $10 million of bank debt is secured by a portion of the Plant Kraft property.
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NOTES (continued) Savannah Electric and Power Company 1996 Annual Report
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $1.6 million for 1996, $1.3 million for 1995, and $1.5 million for 1994. 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, 1996, estimated future minimum lease payments for non-cancelable operating leases were as follows:
Amounts -------------------- (in thousands) 1997 $1,413 1998 1,135 1999 497 2000 485 2001 483 2002 and thereafter 7,935 - -------------------------------------------------------------
6. INCOME TAXES
At December 31, 1996, tax-related regulatory assets and liabilities were $19 million and $23 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 the federal and state income tax provisions are as follows:
1996 1995 1994 -------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $ 7,084 $10,427 $11,736 Deferred -- current year 8,216 5,290 2,106 -- reversal of prior years (1,989) (1,661) (755) - ----------------------------------------------------------------- 13,311 14,056 13,087 - ----------------------------------------------------------------- State -- Currently payable 575 1,941 2,064 Deferred -- current year 1,216 695 188 -- reversal of prior years 39 35 86 - ----------------------------------------------------------------- 1,830 2,671 2,338 - ----------------------------------------------------------------- Total 15,141 16,727 15,425 Less income taxes credited to other income (1,034) (651) (864) - ----------------------------------------------------------------- Total income taxes charged to operations $16,175 $17,378 $16,289 =================================================================
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:
1996 1995 -------------------- Deferred tax liabilities: (in thousands) Accelerated depreciation $67,104 $62,822 Property basis differences 9,550 11,330 Other 5,703 1,511 - ---------------------------------------------------------------- Total 82,357 75,663 - ---------------------------------------------------------------- Deferred tax assets: Pension and other benefits 5,183 3,660 Other 2,186 3,818 - ---------------------------------------------------------------- Total 7,369 7,478 - ---------------------------------------------------------------- Net deferred tax liabilities 74,988 68,185 Portions included in current assets, net 1,666 5,967 - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $76,654 $74,152 ================================================================
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 1996, 1995 and 1994. At December 31, 1996, all investment tax credits available to reduce federal income taxes payable had been utilized.
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NOTES (continued) Savannah Electric and Power Company 1996 Annual Report
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
1996 1995 1994 ----------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of federal income tax benefit 3 4 4 Other (1) - - -------------------------------------------------------------- Effective income tax rate 37% 39% 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 May 1996, the Company issued $20 million in 6.90% Series First Mortgage Bonds maturing in 2006 and $10 million of 6.88% term notes maturing in 2001. Using the proceeds from such sales, the Company redeemed in July 1996 all of its remaining outstanding 9 3/8% Series First Mortgage Bonds due July 2021.
The sinking fund requirements of first mortgage bonds were satisfied by cash redemption in 1996 and 1995. The 1997 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2001 applicable to long-term debt are as follows: $0.6 million in 1997; $20.5 million in 1998; $0.5 million in 1999; $0.4 million in 2000; and $10.4 million in 2001.
Details of pollution control obligations and other long-term debt at December 31 are as follows:
1996 1995 ----------------------- (in thousands) Collateralized obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds -- Variable rate (3.20% at 1/1/97) due 2016 $ 4,085 $ 4,085 6 3/4% due 2022 13,870 13,870 Capital lease obligations -- Coal unloading facility Variable rate (5.60% at 1/1/97) 6,667 - Transportation fleet 421 485 Notes Payable -- 6.88% due 2001 10,000 - Variable rate (5.75% at 1/1/97) due 1998 15,000 15,000 Variable rate (5.73% at 1/1/97) due 1998 5,000 5,000 - ---------------------------------------------------------------- Total $55,043 $38,440 ================================================================
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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NOTES (continued) Savannah Electric and Power Company 1996 Annual Report
The Company leased combustion turbine generating equipment under a non-cancelable lease that expired in 1995. In December 1995, the Company exercised its option to purchase this equipment. The Company currently leases a portion of its transportation fleet. Under the terms of these leases, the Company is responsible for taxes, insurance and other expenses.
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:
1996 1995 ---------------------- (in thousands) Bond sinking fund requirement $1,100 $1,200 Less: Portion to be satisfied by certifying property additions 1,100 - - -------------------------------------------------------------------- Cash sinking fund requirement - 1,200 Other long-term debt maturities (Note 9) 637 207 - -------------------------------------------------------------------- Total $ 637 $1,407 ====================================================================
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, 1996, 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 INFORMATION (Unaudited)
Summarized quarterly financial data for 1996 and 1995 are as follows (in thousands):
Net Income After Operating Operating Dividends on Quarter Ended Revenue Income Preferred Stock - -----------------------------------------------------------------
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
March 1995 $46,743 $ 6,468 $ 2,420 June 1995 57,673 9,920 6,041 September 1995 73,449 16,438 12,693 December 1995 47,864 5,452 2,241 - -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
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Note: NR = Not Rated
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Note: NR = Not Rated
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Note: NR = Not Rated
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STATEMENTS OF INCOME Savannah Electric and Power Company
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STATEMENTS OF INCOME Savannah Electric and Power Company
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STATEMENTS OF INCOME Savannah Electric and Power Company
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STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
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STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
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STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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SAVANNAH ELECTRIC AND POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1996
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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 1997 annual meeting of stockholders. The ages of directors and executive officers in Item 10 set forth below are as of December 31, 1996.
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 57 Served as Director since 3-1-89
Bill M. Guthrie Executive Vice President Age 63 Served as Director since 12-16-88
Whit Armstrong (2) Age 49 Served as Director since 9-24-82
A. W. Dahlberg (2) Age 56 Served as Director since 4-22-94
Peter V. Gregerson, Sr. (2) Age 68 Served as Director since 10-22-93
Carl E. Jones, Jr. (2) Age 56 Served as Director since 4-22-88
Wallace D. Malone, Jr. (2) Age 60 Served as Director since 6-22-90
William V. Muse (2) Age 57 Served as Director since 2-26-93
John T. Porter (2) Age 65 Served as Director since 10-22-93
Gerald H. Powell (2) Age 70 Served as Director since 2-28-86
Robert D. Powers (2) Age 46 Served as Director since 1-24-92
John W. Rouse (2) Age 59 Served as Director since 4-22-88
William J. Rushton, III (2) Age 67 Served as Director since 9-18-70
James H. Sanford (2) Age 52 Served as Director since 8-1-83
John C. Webb, IV (2) Age 54 Served as Director since 4-22-77
John W. Woods (2) Age 65 Served as Director since 4-20-73
(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 26, 1996) 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 ALABAMA acting solely in their capacities as such.
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Identification of executive officers of ALABAMA.
Elmer B. Harris (1) President, Chief Executive Officer and Director Age 57 Served as Executive Officer since 3-1-89
Banks H. Farris Executive Vice President Age 61 Served as Executive Officer since 12-3-91
William B. Hutchins, III Executive Vice President and Chief Financial Officer Age 53 Served as Executive Officer since 12-3-91
Charles D. McCrary Executive Vice President Age 45 Served as Executive Officer since 1-1-91
(1) Previously served as executive officer of ALABAMA from 1979 to 1985.
Each of the above is currently an executive officer of ALABAMA, serving a term running from the last annual meeting of the directors (April 26, 1996) 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 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 Operating Officer of Regions Bank, Birmingham, Alabama. President of the Southern Region, Regions Financial Corporation. He previously served as Chairman and Chief Executive Officer of Regions Bank (formerly First Alabama Bank), Mobile, 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.
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William V. Muse - President of Auburn University. Director of SouthTrust Corporation and American Cast Iron Pipe Company.
John T. Porter - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama. Director of Citizen Federal Bank.
Gerald H. Powell - President, Dixie Clay Company of Alabama, Inc. (refractory clay producer), Jacksonville, Alabama.
Robert D. Powers - President and Director, The Eufaula Agency, Inc. (real estate and insurance), Eufaula, Alabama.
John W. Rouse - President and Chief Executive Officer of Southern Research Institute (non-profit research institute), Birmingham, Alabama. 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.
John W. Woods - Director of Protective Life Corporation and McWane, Inc. During 1996, he served as Chairman of AmSouth Bancorporation and Chairman of AmSouth Bank of Alabama.
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.
William B. Hutchins, III - Elected in 1991; Chief Financial Officer, responsible primarily for providing the overall management of accounting and financial planning activities. He previously served as Senior Vice President and Chief Financial Officer from 1991 to 1994.
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 52 Served as Director since 1-1-94
Warren Y. Jobe Executive Vice President, Treasurer and Chief Financial Officer Age 56 Served as Director since 8-1-82
Bennett A. Brown (1) Age 67 Served as Director since 5-15-80
A. W. Dahlberg (1) Age 56 Served as Director since 6-1-88
William A. Fickling, Jr. (1) Age 64 Served as Director since 4-18-73
L. G. Hardman III (1) Age 57 Served as Director since 6-25-79
James R. Lientz, Jr. (1) Age 53 Served as Director since 7-21-93
William A. Parker, Jr. (1) Age 69 Served as Director since 5-19-65
G. Joseph Prendergast (1) Age 51 Served as Director since 1-20-93
Herman J. Russell (1) Age 66 Served as Director since 5-18-88
Gloria M. Shatto (1) Age 65 Served as Director since 2-20-80
William Jerry Vereen (1) Age 56 Served as Director since 5-18-88
Carl Ware (1) (2) Age 53 Served as Director since 2-15-95
Thomas R. Williams (1) Age 68 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 15, 1996) 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 52 Served as Executive Officer since 1-1-94
Warren Y. Jobe Executive Vice President, Treasurer, Chief Financial Officer and Director Age 56 Served as Executive Officer since 5-19-82
William C. Archer, III Executive Vice President - External Affairs Age 48 Served as Executive Officer since 4-6-95
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W. G. Hairston, III Executive Vice President - Nuclear Age 52 Served as Executive Officer since 6-1-93
Gene R. Hodges Executive Vice President - Customer Operations Age 58 Served as Executive Officer since 11-19-86
William P. Bowers Senior Vice President - Marketing Age 40 Served as Executive Officer since 9-22-95
Wayne T. Dahlke Senior Vice President - Power Delivery Age 55 Served as Executive Officer since 4-19-89
James K. Davis Senior Vice President - Corporate Relations Age 56 Served as Executive Officer since 10-1-93
Robert H. Haubein Senior Vice President - Fossil/Hydro Power Age 56 Served as Executive Officer since 2-19-92
Fred D. Williams Senior Vice President - Wholesale Power Marketing Age 52 Served as Executive Officer since 11-18-92
Each of the above is currently an executive officer of GEORGIA, serving a term running from the last annual meeting of the directors (May 15, 1996) 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 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 since 1992. Responsible for financial and accounting operations and planning, internal auditing, procurement, corporate services, corporate secretary and treasury operations.
Bennett A. Brown - Retired as Chairman of the Board of NationsBank on December 31, 1992. Previously Chairman of the Board and Chief Executive Officer of C&S/Sovran Corporation. Director of Cousins Properties.
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 and President of Beech Street Corporation (provider of managed care services).
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.
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William A. Parker, Jr. - Chairman of the Board, Seminole Investment Co., L.L.C. (private investments), Atlanta, Georgia. Director of SOUTHERN, Genuine Parts Company, Atlantic Investment Company, Post Properties, Inc. and Haverty Furniture Companies, Inc.
G. Joseph Prendergast - Chairman, Wachovia Bank of Georgia, N.A. since 1994. Chairman, Wachovia Bank of South Carolina, and Director, Wachovia Bank of North Carolina. He previously served as President and Chief Executive Officer, Wachovia Corporation of Georgia and Wachovia Bank of Georgia, N.A. from 1993 to 1994 and from 1988 to 1993 as Executive Vice President of Wachovia Corporation of Georgia and President of Wachovia Corporate Services, Inc.
Herman J. Russell - Chairman of the Board, H. J. Russell & Company (construction), Atlanta, Georgia. Chairman of the Board, Citizens Trust Bank, and Citizens Bancshares Corporation Atlanta, Georgia. Director of Wachovia Corporation and National Service Industries. Member of Board of Trustees, First Union Real Estate Equity 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 Group and Blue Cross/Blue Shield of Georgia.
Carl Ware - President, Africa Group, Coca-Cola International since 1991.
Thomas R. Williams - President of The Wales Group, Inc. (investments), Atlanta, Georgia. Director of ConAgra, Inc., BellSouth Corporation, 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. Vice President - Northern Region from March 1992 to August 1992 and Vice President - Metro Region from 1990 to March 1992.
W. G. Hairston, III - Executive Vice President - Nuclear since 1993. Also, he has served as President and Chief Operating Officer of Southern Nuclear since May 1993 and Chief Executive Officer since December 1993. Executive Vice President of Southern Nuclear from 1992 to 1993 and Senior Vice President of Southern Nuclear from 1990 to 1992.
Gene R. Hodges - Executive Vice President - Customer Operations, Power Delivery and Safety. Senior Vice President - Region/Land Operations from 1990 to 1992.
William P. Bowers - Senior Vice President - Marketing since 1995. Vice President - Retail Sales and Service from 1992 to 1995 and Vice President - Marketing from 1990 to 1992.
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 - Wholesale Power Marketing since August 1995. Senior Vice President - Bulk Power Markets from 1992 to August 1995. Vice President - Bulk Power Markets from 1984 to 1992. 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 58 Served as Director since 2-1-94
Paul J. DeNicola (1) Age 48 Served as Director since 4-19-91
Fred C. Donovan (1) Age 56 Served as Director since 1-18-91
W. Deck Hull, Jr. (1) Age 64 Served as Director since 10-14-83
Joseph K. Tannehill (1) Age 63 Served as Director since 7-19-85
Barbara H. Thames (1) Age 56 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 25, 1996) for one year until the next annual meeting or until a successor is elected and qualified, except for Ms. Thames whose election was effective on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GULF acting solely in their capacities as such. Identification of executive officers of GULF.
Travis J. Bowden President, Chief Executive Officer and Director Age 58 Served as Executive Officer since 2-1-94
Francis M. Fisher, Jr. Vice President - Power Delivery and Customer Operations Age 48 Served as Executive Officer since 5-19-89
John E. Hodges, Jr. Vice President - Marketing and Employee/External Affairs Age 53 Served as Executive Officer since 5-19-89
G. Edison Holland, Jr. Vice President - Power Generation/Transmission and Corporate Counsel Age 44 Served as Executive Officer since 4-25-92
Arlan E. Scarbrough Vice President - Finance Age 60 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 26, 1996) for one year until the next annual meeting or until his successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of GULF acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
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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. Director of Baptist Health Care, Inc.
W. Deck Hull, Jr. - Vice Chairman of the SunTrust Bank, West Florida, Panama City, Florida. He previously served as President and Chief Executive Officer and Director of the Sun Commercial Bank, Panama City, Florida from 1989 to 1992.
Joseph K. Tannehill - President and Chief Executive Officer of Merrick International Industries, Lynn Haven, Florida. Director of Florida First Bank, Panama City, Florida.
Barbara H. Thames - Chief Executive Officer of Santa Rosa Medical Center, Milton, Florida since 1991.
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. Director of Barnett Bank of West Florida, Pensacola, Florida.
G. Edison Holland, Jr. - Elected Vice President and Corporate Counsel in 1992 and Vice President - Power Generation/Transmission and Corporate Counsel in 1995; responsible for generation and transmission of electric energy, all legal matters associated with GULF and serves as compliance officer. Also serves, since 1982, as a partner in the law firm, Beggs & Lane.
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 48 Served as Director since 3-27-95
Paul J. DeNicola (1) Age 48 Served as Director since 5-1-89
Edwin E. Downer (1) Age 65 Served as Director since 4-24-84
Robert S. Gaddis (1) Age 65 Served as Director since 1-21-86
Walter H. Hurt, III (1) Age 61 Served as Director since 4-6-82
Aubrey K. Lucas (1) Age 62 Served as Director since 4-24-84
George A. Schloegel (1) Age 56 Served as Director since 7-26-95
Philip J. Terrell (1) Age 43 Served as Director since 2-22-95
N. Eugene Warr (1) Age 61 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 2, 1996) 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 48 Served as Executive Officer since 3-27-95
H. E. Blakeslee Vice President - Customer Services and Marketing Age 56 Served as Executive Officer since 1-25-84
F. D. Kuester (1) Vice President - Power Generation and Delivery Age 46 Served as Executive Officer since 3-28-94
Don E. Mason Vice President - External Affairs and Corporate Services Age 55 Served as Executive Officer since 7-27-83
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer Age 44 Served as Executive Officer since 1-1-95
(1) Resigned effective March 1, 1997, to assume the position of Director - Commercial of SOUTHERN's Hong Kong-based affiliate, Consolidated Electric Power Asia.
Each of the above, except for Mr. Kuester, is currently an executive officer of MISSISSIPPI, serving a term running from the last annual meeting of the directors (April 24, 1996) 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.
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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, All Saints Church, Inverness, Mississippi, and St. Thomas Church, Belzoni, Mississippi. Retired newspaper editor and publisher.
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 retail marketing, rates and wholesale marketing, division operations, the customer service center and distribution services.
F. D. Kuester - Elected Vice President in 1994. 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 previously served as Manager of Business and New Project Design/Development of SCS from 1993 to 1994 and Vice President of SCS from 1990 to 1993.
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.
Arthur M. Gignilliat, Jr. President and Chief Executive Officer Age 64 Served as Director since 9-1-82
Helen Quattlebaum Artley (1) Age 69 Served as Director since 5-17-77
Archie H. Davis (1) Age 55 Served as Director since 2-18-97
Paul J. DeNicola (1) Age 48 Served as Director since 3-14-91
Walter D. Gnann (1) Age 61 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 51 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 60 Served as Director since 5-17-77
Frederick F. Williams, Jr. (1) Age 69 Served as Director since 7-2-75
(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 21, 1996) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Davis 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/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.
Arthur M. Gignilliat, Jr. President, Chief Executive Officer and Director Age 64 Served as Executive Officer since 2-15-72
W. Miles Greer Vice President - Marketing and Customer Services Age 53 Served as Executive Officer since 11-20-85
Larry M. Porter Vice President - Operations Age 51 Served as Executive Officer since 7-1-91
Kirby R. Willis Vice President, Treasurer and Chief Financial Officer Age 45 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 16, 1996) 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 SAVANNAH acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
Arthur M. Gignilliat, Jr. - Elected President and Chief Executive Officer in 1984. Director of Savannah Foods and Industries, Inc.
Helen Quattlebaum Artley - Homemaker and Civic Worker.
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Archie H. Davis - President and Chief Executive Officer of The Savannah Bank, Savannah, Georgia. Previously served as President of C&S in Savannah, Georgia. Chairman of the Board of Candler Health Services. Member of the Board of Directors of Thomaston Mills, Thomaston, Georgia.
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 National Bank of Georgia and Savannah Foods and Industries, Inc.
Frederick F. Williams, Jr. - Retired Partner and Consultant, Hilb, Rogal and Hamilton Employee Benefits, Incorporated (Insurance Brokers), formerly Jones, Hill & Mercer.
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. 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.
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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 1996 for each of the operating affiliates (ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH).
Key terms used in this Item will have the following meanings:-
See next page for footnotes.
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See next page for footnotes.
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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 and supplemental defined benefit plans in effect during 1996 for ALABAMA, GEORGIA, GULF and MISSISSIPPI. Employee compensation covered by the pension and supplemental benefit plans for pension purposes is limited to the average of the highest three of the final 10 years' base salary and wages (reported under column titled "Salary" 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 $3,000 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, 1996, the applicable compensation levels and years of accredited service are presented in the following tables:
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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 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.
1 The number of accredited years of service includes 10 years credited to both Mr. Bowden and Mr. Holland pursuant to individual supplemental pension agreements.
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As of December 31, 1996, the applicable compensation levels and years of accredited service are presented in the following table:-
SAVANNAH has in effect a voluntary deferred compensation plan for certain executive employees pursuant to which such employees may defer a portion of their respective annual salaries. In addition, SAVANNAH has a supplemental executive retirement plan for certain of its executive employees. The deferred compensation plan is designed to provide supplemental retirement or survivor benefit payments. The supplemental executive retirement plan is also designed to provide retiring executives of SAVANNAH 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 compensation (including deferrals under the deferred compensation plan). Both of these plans are unfunded and the liability is payable from general funds of SAVANNAH. The deferred compensation plan became effective December 1, 1983, and all of SAVANNAH's executive officers are participating in the plan. In addition, all executives are participating in the supplemental executive retirement plan.
In order to provide for its liabilities under the deferred compensation plan and the supplemental executive retirement plan, SAVANNAH has purchased life insurance on participating executive employees in actuarially determined amounts which, based upon assumptions as to mortality experience, policy dividends, tax effects, and other factors which, if realized, along with compensation deferred by employees and the death benefits payable to SAVANNAH, are expected to cover all such insurance premium payments, and all benefit payments to participants, plus a factor for the cost of funds of SAVANNAH.
The following table sets forth the estimated combined annual pension benefits under the pension plan and supplemental executive retirement plan in effect during 1996 which are payable by SAVANNAH to executives 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 1996 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 may be deferred until membership on the board is terminated.
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, have 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 elect to receive the benefit buy-out must defer receipt until membership on the board is terminated. Directors who elect 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 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, 1996 in addition to or in lieu of that specified by the standard arrangements specified above.
Employment Contracts and Termination of Employment and Change in Control Arrangements.
None.
Report on Repricing of Options.
None.
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Additional Information with Respect to Compensation Committee Interlocks and Insider Participation in Compensation Decisions.
ALABAMA
Elmer B. Harris serves on the Compensation Committee of AmSouth Bancorporation. John W. Woods, a director of ALABAMA, served as Chairman of AmSouth Bancorporation during 1996.
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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, 1996. 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, 1996.
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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 Operating Officer of Regions Bank, Birmingham, Alabama; Mr. Wallace D. Malone is Chairman and Chief Executive Officer of SouthTrust Corporation, Birmingham, Alabama. During 1996, 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 1996, 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 1996, GEORGIA leased a building from Riverside Manufacturing Co. for approximately $77,000. 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. is Vice Chairman of SunTrust Bank, West Florida, Panama City, Florida. During 1996, 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.
The firm of Beggs & Lane, P.A. serves as local counsel for GULF and received from GULF approximately $960,994 for services rendered. Mr. G. Edison Holland, Jr. is a partner in the firm and also serves as Vice President - Power Generation/Transmission and Corporate Counsel of GULF.
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 and Mr. N. Eugene Warr is a director of Coast Community Bank. During 1996, these banks furnished a number of regular banking services in the ordinary course of business to MISSISSIPPI. MISSISSIPPI intends to maintain normal banking relations with the aforesaid banks in the future.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
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SAVANNAH
Transactions with management and others. None
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
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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