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 SEI, Communications, Southern Nuclear, SCS (the system service company), Southern Development and other direct and indirect subsidiaries. SEI 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. A further description of SEI's business and organization follows later in this section under "New Business Development." 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 explores, develops and markets energy management services and other business lines relating to SOUTHERN's core business of generating and distributing energy.
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, SEI, 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. SEI, Southern Development and 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. Southern Nuclear also has a contract to provide GEORGIA with technical and other services to support GEORGIA's operation of plants Hatch and Vogtle. Applications are now pending before the NRC for amendments to the Hatch and Vogtle operating licenses which, if approved, would authorize Southern Nuclear to become the operator. 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 SEI and other subsidiaries.
SEI's primary business focus is international and domestic cogeneration, the independent power market, and the privatization and development of generation, transmission and distribution facilities in the international market. During 1995, SEI also entered the business of power marketing.
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 September 1995, SOUTHERN acquired SWEB, one of the United Kingdom's 12 regional electric distribution companies, for approximately $1.8 billion. SWEB's main business is the distribution of electricity to customers in the Southwest of England. Based in Bristol, SWEB serves approximately 1.3 million customers in an area roughly the size of Connecticut, with almost 2 million residents. SWEB is also a supplier of electricity to franchise customers in its authorized area and to customers in the competitive second-tier market. Through its 7.7% equity investment in Teesside Power Limited, a combined cycle gas turbine plant with a capacity of 1,875 megawatts, SWEB is involved in power generation. In addition, SWEB is involved in certain non-regulated activities which include gas supply and telecommunications. For additional information regarding the acquisition of SWEB, reference is made to Note 14 to SOUTHERN's financial statements in Item 8 herein.
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See Item 2

Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1995, operated 33 hydroelectric generating stations, 32 fossil fuel generating stations and three nuclear generating stations. The amounts of capacity owned by each company are shown in the table below.
------------------------------------------------------------ Nameplate Generating Station Location Capacity (1) ------------------------------------------------------------ (Kilowatts) Fossil Steam Gadsden Gadsden, AL 120,000 Gorgas Jasper, AL 1,221,250 Barry Mobile, AL 1,525,000 Chickasaw Chickasaw, AL 40,000 Greene County Demopolis, AL 300,000 (2) Gaston Unit 5 Wilsonville, AL 880,000 Miller Birmingham, AL 2,532,288 (3) --------- ALABAMA Total 6,618,538 ---------
Arkwright Macon, GA 160,000 Atkinson Atlanta, GA 180,000 Bowen Cartersville, GA 3,160,000 Branch Milledgeville, GA 1,539,700 Hammond Rome, GA 800,000 McDonough Atlanta, GA 490,000 McManus Brunswick, GA 115,000 Mitchell Albany, GA 170,000 Scherer Macon, GA 750,924 (4) Wansley Carrollton, GA 925,550 (5) Yates Newnan, GA 1,250,000 --------- GEORGIA Total 9,541,174 ---------
Crist Pensacola, FL 1,045,000 Lansing Smith Panama City, FL 305,000 Scholz Chattahoochee, FL 80,000 Daniel Pascagoula, MS 500,000 (6) Scherer Unit 3 Macon, GA 204,500 (4) --------- GULF Total 2,134,500 ---------
Eaton Hattiesburg, MS 67,500 Sweatt Meridian, MS 80,000 Watson Gulfport, MS 1,012,000 Daniel Pascagoula, MS 500,000 (6) Greene County Demopolis, AL 200,000 (2) ----------- MISSISSIPPI Total 1,859,500 -----------
----------------------------------------------------------------
---------------------------------------------------------------- Nameplate Generating Station Location Capacity ---------------------------------------------------------------- (Kilowatts)
McIntosh Effingham County, GA 163,117 Kraft Port Wentworth, GA 281,136 Riverside Savannah, GA 102,278 ------------ SAVANNAH Total 546,531 ------------
Gaston Units 1-4 Wilsonville, AL (SEGCO) 1,000,000 (7) ------------ Total Fossil Steam 21,700,243 ------------
Nuclear Steam Farley Dothan, AL (ALABAMA) 1,720,000 ------------ Hatch Baxley, GA 816,630 (8) Vogtle Augusta, GA 1,060,240 (9) ------------ GEORGIA Total 1,876,870 ------------ Total Nuclear Steam 3,596,870 ------------
Combustion Turbines Greene County Demopolis, AL (ALABAMA) 400,000 ----------- 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 2,774,054 ----------- 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 30,731,628 =========== ---------------------------------------------------------------
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 SOUTHERN system are owned in fee by the operating affiliates and SEGCO. 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.
The all-time maximum demand on the SOUTHERN system 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 Southern electric system 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, 1995, 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 has remaining commitments to purchase declining fractions of MEAG's capacity and energy until December 1996 for Unit 2 and, with regard to a portion of a 5% interest owned by MEAG, 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 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. The plant went into commercial operation in 1995. GEORGIA's net investment in the plant is approximately $190 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 is scheduled to be in commercial operation by the end of 1996, and will be constructed, operated, and maintained by FPC. GEORGIA will have a one-third interest in the 150-megawatt unit, with use of 100% of the capacity from June through September. FPC will have the capacity the remainder of the year. GEORGIA's investment in the unit at completion is estimated to be $14 million. Also, GEORGIA entered into a separate four-year purchase power contract with FPC. Beginning in 1996, GEORGIA will purchase 400 megawatts of capacity. In 1998, this amount will decline to 200 megawatts for the remaining two years.
Sale of Property
Reference is made to Note 6 to SOUTHERN's and 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 four 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, 1991 to December 31, 1995, the operating affiliates, SEGCO, SCS, Southern Nuclear, Communications and SEI recorded gross property additions and retirements as follows:
================================================== Gross Property Additions Retirements --------------- ------------- (in millions) ALABAMA (1) $2,290 $ 357 GEORGIA (2) 2,850 1,864 GULF 350 125 MISSISSIPPI 433 82 SAVANNAH 179 16 SEGCO 60 14 SCS 111 122 Southern Nuclear 17 4 Communications 162 - SEI 154 6 - - -------------------------------------------------- SOUTHERN system $6,606 $2,590 ==================================================
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 $691 million attributable to 1991 through 1995 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."
(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 $31 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.
(3) ALABAMA, GEORGIA and MISSISSIPPI v. TVA, et al. (U.S. District Court for the Northern District of Alabama)
On January 12, 1996, ALABAMA, GEORGIA and MISSISSIPPI filed an action seeking to enjoin the TVA from violating a 1959 act which prohibits the TVA from selling power outside the area that was being served by it in 1957. LG&E Power Marketing, Inc. (LPM), also a defendant, has entered into an agreement with TVA for the sale of power purchased by LPM from TVA to organizations outside the TVA's statutorily defined service territory, which the plaintiffs contend is in violation of the 1959 act.
(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, SEI, SCS, Southern Nuclear, Southern Development and 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, 1995.
A. W. Dahlberg Chairman, President and Chief Executive Officer Age 55 Elected in 1985; President and Chief Executive Officer of GEORGIA from 1988 through 1993. He was elected Executive Vice President of SOUTHERN in 1991. 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 47 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 and President and Chief Executive Officer of MISSISSIPPI from 1989 to 1991.
H. Allen Franklin Executive Vice President and Director Age 51 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 56 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 47 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 and previously held that position from 1989 to 1991.
W. L. Westbrook Financial Vice President, Chief Financial Officer and Treasurer Age 56 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 46 Elected in 1995; President and Chief Executive Officer of SEI since 1992. He previously served as Senior Vice President of GEORGIA from 1989 to 1992.
Bill M. Guthrie Vice President Age 62 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 51 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, except Mr. Hairston, serving a term running from the last annual meeting of the directors (July 17, 1995) 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 and as adjusted to reflect a two-for-one stock split in the form of a stock distribution for each share held as of February 7, 1994, during each quarter for the past two years were as follows:
------------------------------------------ High Low ----------- -------- 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
First Quarter $22 $18-1/2 Second Quarter 20-1/2 17-3/4 Third Quarter 20 17 Fourth Quarter 21 18-1/4 -------------------------------------------
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 29, 1996, the closing price of SOUTHERN's common stock was $23-7/8.
(b) Number of SOUTHERN's common stockholders at December 31, 1995: 225,739
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 1995 1994 ----------------------------------------------------
SOUTHERN First $201,866 $191,262 Second 203,060 191,262 Third 203,061 191,475 Fourth 203,178 192,758
ALABAMA First 71,900 66,500 Second 69,500 67,000 Third 69,300 66,900 Fourth 74,300 67,600
GEORGIA First 113,900 106,600 Second 110,200 107,200 Third 109,700 107,200 Fourth 117,700 108,300
GULF First 11,700 10,900 Second 11,300 11,000 Third 11,300 11,000 Fourth 12,100 11,100
MISSISSIPPI First 9,900 8,500 Second 9,600 8,500 Third 9,600 8,500 Fourth 10,300 8,600
SAVANNAH First 4,400 4,100 Second 4,300 4,100 Third 4,300 4,100 Fourth 4,600 4,000 ----------------------------------------------------
In January 1994, SOUTHERN's board of directors authorized a two-for-one common stock split in the form of a stock distribution for each share held as of February 7, 1994. For all reported common stock data, the number of common shares outstanding and per share amounts for earnings, dividends, and market price have been adjusted to reflect the stock distribution.
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The dividend paid per share by SOUTHERN was 29.5(cent) for each quarter of 1994 and 30.5(cent) for each quarter of 1995. The dividend paid on SOUTHERN's common stock for the first quarter of 1996 was raised to 31.5(cent) per share.
The amount of dividends on their common stock that may be paid by the subsidiary registrants is restricted in accordance with their 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, 1995, were as follows:
- - --------------------------------------------- Retained Restricted Earnings Amount -------------------------- (in millions) ALABAMA $1,161 $ 807 GEORGIA 1,570 897 GULF 180 101 MISSISSIPPI 157 118 SAVANNAH 105 62 Consolidated 3,483 1,990 - - ---------------------------------------------
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-39 through II-50.
ALABAMA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-79 through II-92.
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-170 through II-183.
MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-210 through II-223.
SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-246 through II-258.
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-15.
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-54 through II-60.
GEORGIA. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-96 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-151.
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-187 through II-193.
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-227 through II-232.
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Item 8.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 1995 FINANCIAL STATEMENTS
Item 9.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
II-4
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT The Southern Company and Subsidiary Companies 1995 Annual Report
The management of The 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 The 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 21, 1996 II-6
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and to the Stockholders of The Southern Company:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company (a Delaware corporation) and subsidiary companies as of December 31, 1995 and 1994, 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, 1995. 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-16 through II-38) referred to above present fairly, in all material respects, the financial position of The Southern Company and subsidiary companies as of December 31, 1995 and 1994, and the results of their operations and their cash flows for the periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The Southern Company and Subsidiary Companies 1995 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
This year's financial performance continues to support The Southern Company's goal to become America's Best Diversified Utility. The core business of selling electricity in the Southeast remained strong, while the non-core business expanded both internationally and domestically. The financial results for 1995 demonstrate a very successful year with several records being set. Net income of $1.1 billion and earnings per share of $1.66 for 1995 both established record highs. Southern Company common stock reached an all-time high closing price of 24 5/8, surpassing the previous record of 23 3/8 set in 1993. Continued cost controls and the strong demand for electricity were the dominant forces that favorably affected earnings in 1995.
Costs related to the work force reduction programs implemented in 1995 and 1994 decreased earnings by 2 cents and 9 cents per share, respectively. These costs are expected to be recovered through future savings in approximately two years following each program's implementation. Additional non-operating or non-recurring items affected earnings in 1995 and 1994. After excluding these items in both years, 1995 earnings from operations were $1.1 billion -- or $1.71 per share -- an increase of $108 million compared with 1994. The non-operating items that affected earnings were as follows:
Consolidated Earnings Net Income Per Share --------------- ---------------- 1995 1994 1995 1994 --------------- ---------------- (in millions) Earnings as reported $1,103 $ 989 $1.66 $1.52 - - --------------------------------------------------------------------- Work force reduction programs 17 61 .02 .09 Sale of facilities (12) (28) (.02) (.04) Demand-side costs 17 - .03 - Environmental cleanup 5 5 .01 .01 Miscellaneous 5 - .01 - - - --------------------------------------------------------------------- Total non-operating 32 38 .05 .06 - - --------------------------------------------------------------------- Earnings from operations $1,135 $1,027 $1.71 $1.58 ===================================================================== Amount and percent change $108 10.6% $0.13 8.2% - - ---------------------------------------------------------------------
In 1995, non-operating items -- both positive and negative -- had an impact on earnings, which resulted in a net reduction of $32 million. These items were: (1) Costs associated with work force reduction programs implemented primarily in 1995 decreased earnings. (2) The last in a series of four separate transactions to sell Plant Scherer Unit 4 to two Florida utilities increased earnings. (3) Georgia Power's demand-side conservation costs that were not recovered from customers decreased earnings. (4) Environmental-cleanup costs decreased earnings.
In 1994, earnings were $989 million or $1.52 per share -- down 5 cents from the per share amount reported in 1993. Earnings in 1994 were significantly affected by costs related to work force reduction programs and milder than normal temperatures.
Dividends paid on common stock during 1995 were $1.22 per share or 30 1/2 cents per quarter. During 1994 and 1993, dividends paid per share were $1.18 and $1.14, respectively. In January 1996, The Southern Company board of directors raised the quarterly dividend to 31 1/2 cents per share or an annual rate of $1.26 per share.
Acquisitions
Southern Electric International (Southern Electric) owns and manages international and domestic non-core businesses for The Southern Company. Southern Electric acquired several businesses in late 1994 and in 1995. These businesses have been included in the consolidated statements of income since the date of acquisition and not reflected in prior periods. These acquisitions account for a significant portion of the amount of change in revenues and certain expenses from year to year. Therefore to facilitate discussing the results of operations, Southern Electric's 1995 variances are shown separately. These variances are predominantly acquisition related and require no further explanation. II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Revenues
Operating revenues increased in 1995 and decreased in 1994 as a result of the following factors:
Increase (Decrease) From Prior Year ------------------------------ 1995 1994 1993 ------------------------------ Retail -- (in millions) Change in base rates $ - $ 3 $ 3 Sales growth 177 153 104 Weather 143 (177) 198 Fuel cost recovery and other 134 (107) 199 ------------------------------------------------------------- Total retail 454 (128) 504 ------------------------------------------------------------- Sales for resale -- Within service area 39 (87) 38 Outside service area (90) (108) (184) ------------------------------------------------------------- Total sales for resale (51) (195) (146) Southern Electric 458 131 54 Other operating revenues 22 - 4 ------------------------------------------------------------- Total operating revenues $883 $(192) $ 416 ============================================================= Percent change 10.6% (2.3)% 5.2% -------------------------------------------------------------
Retail revenues of $7.6 billion in 1995 increased 6.4 percent from last year, compared with a decrease of 1.8 percent in 1994. 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 $399 million in 1995, up 11 percent from the prior year. This increase resulted primarily from the prolonged hot summer weather, which increased the demand for electricity. Revenues from sales for resale within the service area were $360 million in 1994, down 19 percent from the prior year. The decrease resulted from certain municipalities and cooperatives in the service area retaining more of their own generation at facilities jointly owned with Georgia Power.
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.
1995 1994 1993 --------------------------------- (in millions) Capacity $237 $276 $350 Energy 151 176 230 ------------------------------------------------------ Total $388 $452 $580 ======================================================
Capacity revenues decreased in 1995 and 1994 because the amount of capacity under contract declined, as scheduled, by some 100 megawatts and 400 megawatts, respectively. Additional declines in capacity are not scheduled until after 1999.
Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1995 and the percent change by year were as follows:
Percent Change ---------------------------- (billions of Amount kilowatt-hours) 1995 1995 1994 1993 ------------- ---------------------------- Residential 39.1 9.2% (2.6)% 9.5% Commercial 35.9 5.5 3.8 5.9 Industrial 51.7 2.7 3.2 1.9 Other 0.9 2.1 3.8 4.6 ----------- Total retail 127.6 5.4 1.6 5.3 Sales for resale -- Within service area 9.5 16.2 (38.5) 9.5 Outside service area 9.1 (15.1) (13.5) (25.2) ----------- Total 146.2 4.4 (3.4) 2.1 ===================================================================
The rate of increase in 1995 retail energy sales was fostered by the impact of weather. Residential energy sales surged upward as a result of hotter-than-normal summer weather in 1995, compared with the extremely mild summer of 1994. Commercial and industrial sales continue to show moderate gains in excess of the national average. This reflects the strength of business and economic conditions in The Southern Company's service area. Energy sales to retail customers are projected to increase at an average annual rate of 1.9 percent during the period 1996 through 2006.
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 continued to decrease in 1995 and 1994, primarily as a result of the scheduled decline in megawatts of capacity under contract.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Expenses
Total operating expenses of $7.3 billion for 1995 increased $712 million compared with the prior year. Core business expenses increased $322 million, and Southern Electric comprised the remainder. The costs to produce and deliver electricity for the core business in 1995 increased by $120 million to meet higher energy demands. Depreciation expenses and property taxes increased by $78 million as a result of additional utility plant being placed into service. The amortization of deferred expenses related to Plant Vogtle increased by $49 million in 1995 when compared with the prior year. For additional information concerning Plant Vogtle, see Note 1 to the financial statements under "Plant Vogtle Phase-In Plans."
In 1994, operating expenses of $6.6 billion declined 2.1 percent compared with 1993. The decrease was attributable to less energy being sold. Total production costs were down $297 million. However, costs related to the 1994 work force reduction programs increased operating expenses by $100 million. Also, a $39 million increase in the amortization of deferred Plant Vogtle expenses compared with the amount in 1993 contributed to offset the decrease in operating expenses.
Fuel costs constitute the single largest expense for The Southern 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 -- within the core business service area -- were as follows:
1995 1994 1993 --------------------------- Total generation (billions of kilowatt-hours) 147 142 144 Sources of generation (percent) -- Coal 77 75 78 Nuclear 17 19 17 Hydro 4 5 4 Oil and gas 2 1 1 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.73 1.80 1.90 Nuclear 0.56 0.56 0.54 Oil and gas 3.37 3.99 4.34 Total 1.53 1.56 1.67 - - --------------------------------------------------------------
Fuel and purchased power costs of $2.6 billion in 1995 increased $282 million compared with 1994. Core business increased $73 million and Southern Electric increased $209 million. The operating companies' customer demand for electricity rose by 4.7 billion kilowatt-hours more than in 1994. 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 $2.3 billion in 1994 decreased 10 percent compared with the prior year because of lower energy demands and a lower average cost of fuel per net kilowatt-hour generated.
For 1995, income taxes increased $84 million compared with the prior year. Core business income taxes increased $65 million, and Southern Electric accounted for the remainder. The increase was attributable to additional taxable income from operations. For 1994, income taxes rose $8 million or 1.3 percent above the amount reported for 1993. The increase resulted primarily from the sale of interests in generating plant facilities.
Total gross interest charges and preferred stock dividends increased $39 million from amounts reported in the previous year. These costs for core business continued to decline by $12 million, but Southern Electric interest charges increased by $51 million. The decline is attributable to lower interest rates and continued refinancing activities in 1995. In 1994, these costs were $765 million -- down $66 million or 8.0 percent. As a result of favorable market conditions, $1.1 billion in 1995, $1.0 billion in 1994, and $3.0 billion in 1993 of senior securities were issued for the primary purpose of retiring higher-cost securities.
Effects of Inflation
The 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 The 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. II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1995 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, with non-core business becoming more significant.
Work force reduction programs were implemented in 1995 and 1994 that reduced earnings by $17 million and $61 million, 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 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 Southern 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 Southern Company is aggressively working to maintain and expand its share of wholesale sales in the Southeastern power markets.
Although the Energy Act does not require transmission access to retail customers, retail wheeling initiatives are rapidly evolving and becoming very prominent issues in several states. New federal legislation is being discussed, and legislation allowing customer choice has already been introduced in Florida and Georgia. In order to address these initiatives, numerous questions must be resolved, with the most complex ones relating to transmission pricing and recovery of stranded investments. As the initiatives become a reality, the structure of the utility industry could radically change. Therefore, unless The 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. Conversely, being the low-cost producer could provide significant opportunities to increase market share and profitability by seeking new markets that evolve with the changing regulation.
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 these opportunities, Southern Electric -- 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. In late 1995, South Western Electricity (SWEB) was acquired for approximately $1.8 billion. For additional information on this acquisition, see Note 14 to the financial statements. This British electric distribution utility and other investments made by Southern Electric should increase the opportunities for future earnings growth. At December 31, 1995, Southern Electric's total assets amounted to $5.0 billion.
Demand-side options -- programs that enable customers to lower or alter their peak energy requirements -- have been implemented by some of the system operating companies and are a significant part of integrated resource planning. See Note 3 to the financial statements under "Georgia Power Demand-Side Conservation Programs" for information concerning the recovery of certain costs. Customers can receive cash incentives for participating in these programs as well as reduce their energy requirements. Besides promoting energy efficiency, another benefit of these programs could be the ability to defer the need to construct costly baseload generating facilities further into the future.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry -- including The 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 The 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 increase. Because of the company's current ability to recover closure and removal costs through rates, these changes would not have a significant adverse effect on results of operations. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information.
The 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."
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.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount for an asset may not be recoverable. This statement also imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. The Southern Company adopted the new rules January 1, 1996, with no material effect on the financial statements. However, this conclusion may change in the future as competitive factors influence wholesale and retail pricing in the utility industry.
The FASB has issued Statement No. 123, Accounting for Stock-Based Compensation. This statement establishes a fair value based method of accounting for employee stock options. This method provides for a compensation cost to be charged to results of operations at the grant date. However, the statement allows companies to continue following the accounting prescribed by Accounting Principles Bulletin Opinion No. 25. Opinion No. 25 generally requires compensation cost to be recognized only for the excess of the quoted market price at the grant date over the price that an employee must pay to acquire the stock. The Southern Company has elected to continue with Opinion No. 25.
FINANCIAL CONDITION
Overview
The Southern Company's financial condition continues to remain strong. Both earnings per share and market price per share set new record levels in 1995. Earnings from operations continued to increase in 1995 and exceeded $1.1 billion. Based on this performance, in January 1996, The Southern Company board of directors increased the common stock dividend for the fifth consecutive year.
In 1995, Southern Electric acquired SWEB for approximately $1.8 billion. For more information on the purchase of this British electric distribution utility, see Note 14 to the financial statements.
Another major change in The Southern Company's financial condition was gross property additions of $1.4 billion to utility plant. The majority of funds needed for gross property additions since 1992 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.
The Southern Company has a policy that financial derivatives are to be used only to mitigate business risks and not for speculative purposes. Derivatives have been used by the company on a very limited basis. At December 31, 1995, the credit risk for derivatives outstanding was not material. See Note 1 to the financial statements under "Financial Instruments" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Capital Structure
The Southern Company achieved a ratio of common equity to total capitalization - - -- including short-term debt -- of 42.4 percent in 1995, compared with 44.4 percent in 1994, and 43.8 percent in 1993. The company's goal is to maintain the common equity ratio generally within a range of 40 percent to 45 percent.
During 1995, the subsidiary companies sold $375 million of first mortgage bonds and, through public authorities, $732 million of pollution control revenue bonds. The companies continued to reduce financing costs by retiring higher-cost bonds. Retirements, including maturities, of bonds totaled $1.3 billion during 1995, $973 million during 1994, and $2.5 billion during 1993. Retirements of preferred stock totaled $1 million a year during 1995 and 1994 and $516 million during 1993. As a result, the composite interest rate on long-term debt decreased from 8.2 percent at December 31, 1992, to 7.1 percent at December 31, 1995. During this same period, the composite dividend rate on preferred stock declined from 7.3 percent to 6.5 percent.
In 1995, The Southern Company raised $174 million from the issuance of new common stock under the company's various stock plans. An additional $103 million of new common stock was issued through a public offering in early 1995. At the close of 1995, the company's common stock had a market value of 24 5/8 per share, compared with a book value of $13.10 per share. The market-to-book value ratio was 188 percent at the end of 1995, compared with 160 percent at year-end 1994 and 184 percent at year-end 1993.
Capital Requirements for Construction
The construction program of The Southern Company is budgeted at $1.5 billion for 1996, $1.4 billion for 1997, and $1.3 billion for 1998. The total is $4.2 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 baseload generating plants under construction, and current energy demand forecasts do not require any additional baseload facilities until well into the future. However, within the service area, the construction of combustion turbine peaking units of approximately 600 megawatts of capacity is planned to be completed by 1998 to meet increased peak-hour demands. In addition, 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 $996 million will be required by the end of 1998 for present sinking fund requirements and maturities of long-term debt. Also, the subsidiaries will continue to retire higher-cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- has significantly impacted The 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 The 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 method for issuing allowances is based on the fossil fuel consumed from 1985 through 1987 for each affected generating unit. Emission allowances are transferable and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. The Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
The 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. Compliance with nitrogen oxide emission limits was achieved by the installation of new control equipment at 22 of the original 28 affected generating units. Construction expenditures for Phase I compliance totaled approximately $320 million through 1995.
For Phase II sulfur dioxide compliance, The Southern Company could use emission allowances banked during Phase I, increase fuel switching, install flue gas desulfurization equipment at selected plants, and/or purchase more allowances, depending on the price and availability of allowances. Also, in Phase II, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as required to meet Phase II limits. Therefore, during the period 1996 to 2000, current compliance strategy could require total estimated construction expenditures of approximately $150 million. 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.
Metropolitan Atlanta is classified as a non-attainment area with regard to the ozone ambient air quality standards. Title I of the Clean Air Act requires the state of Georgia to conduct specific studies and establish new control rules - - -- affecting sources of nitrogen oxides and volatile organic compounds -- to achieve attainment by 1999. As the required first step, the state issued rules for the application of reasonably available control technology to reduce nitrogen oxide emissions by May 31, 1995. The results of these new rules required nitrogen oxide controls, above Title IV requirements, on some Georgia Power plants. The EPA along with 37 states is conducting studies to evaluate the benefits of regional controls in meeting the ozone standards. Final attainment rules, based on modeling studies, could require installation of additional controls for nitrogen oxide emissions to meet the 1999 deadline in Atlanta or as part of any regional controls if enacted. A decision on new requirements is expected in 1997. Compliance with any new rules could result in significant additional costs. The actual impact of new rules will depend on the development and implementation of such rules.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The EPA is scheduled to submit a report to Congress on the results of this study during 1996. The report will include a decision on whether additional regulatory control of these substances is warranted. Compliance with any new control standards could result in significant additional costs. The impact of new standards -- if any -- will depend on the development and implementation of applicable regulations.
The EPA is evaluating the need to revise the ambient air quality standards for particulate matter and ozone. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In 1996, the EPA may issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
The 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
any required cleanup costs and have recognized in their respective financial statements costs to clean up known sites. These costs for The Southern Company amounted to $8 million, $8 million, and $41 million in 1995, 1994, and 1993, respectively. 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 Bruswick, 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 The Southern Company's operations. The full impact of these requirements cannot be determined at this time, pending the development and implementation of applicable regulations.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect The Southern Company. The impact of new legislation - - -- if any --will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The Southern Company may require additional equity capital in 1996. The amount and timing of additional equity capital to be raised in 1996 -- as well as in subsequent years -- will be contingent on The 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 1996 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, The Southern Company had approximately $772 million of cash and cash equivalents and $2.8 billion of unused credit arrangements with banks at the beginning of 1996.
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 1998.
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NOTES TO FINANCIAL STATEMENTS The Southern Company and Subsidiary Companies 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Southern Company is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Electric International (Southern Electric), 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 (SEC). The system service company provides, at cost, specialized services to The 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 Electric 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 The Southern Company's nuclear power plants. Southern Development develops new business opportunities related to energy products and services.
The 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.
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:
1995 1994 ------------------------ (in millions) Deferred income taxes $1,386 $1,454 Deferred Plant Vogtle costs 308 432 Premium on reacquired debt 295 298 Demand-side programs 79 97 Department of Energy assessments 73 79 Vacation pay 74 70 Deferred fuel charges 49 51 Postretirement benefits 53 41 Work force reduction costs 56 15 Deferred income tax credits (936) (987) Storm damage reserves (23) (53) Other, net 98 108 - - ----------------------------------------------------------------- Total $1,512 $1,605 =================================================================
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 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 1995, uncollectible accounts continued to average less than 1 percent of revenues.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
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 $140 million in 1995, $152 million in 1994, and $137 million in 1993. 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 2009 at Plant Vogtle, and into 2012 and 2014 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. Alabama Power and Georgia Power -- based on its ownership interests -- estimate their respective remaining liability at December 31, 1995, under this law to be approximately $40 million and $31 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 1995, 3.2 percent in 1994, and 3.3 percent in 1993. 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 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 set periods of time as 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 - - -- both site study costs and ultimate costs -- at December 31, 1995, 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 ==================================================================== (in millions) Ultimate costs: Radiated structures $1,504 $781 $1,018 Non-radiated structures 274 111 230 - - -------------------------------------------------------------------- Total $1,778 $892 $1,248 ====================================================================
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Plant Plant Plant Farley Hatch Vogtle ---------------------------- (in millions) Amount expensed in 1995 $18 $11 $9
Accumulated provisions: Balance in external trust funds $108 $56 $36 Balance in internal reserves 49 30 13 - - ----------------------------------------------------------------- Total $157 $86 $49 =================================================================
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 -- sinking fund -- 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 commission 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
The 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 and 1989, 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 under plans that meet the requirements of FASB Statement No. 92, Accounting for Phase-In Plans. Under these plans, Georgia Power deferred financing costs and depreciation expense until the allowed investment was fully reflected in rates as of October 1991. In 1991, the GPSC modified the Plant Vogtle phase-in plan to begin earlier amortization of the costs deferred under the plan. Also, the GPSC levelized capacity buyback expense from co-owners of Plant Vogtle. Previously, pursuant to two separate interim accounting orders by the GPSC, Georgia Power deferred substantially all operating expenses and financing costs related to Plant Vogtle. Each GPSC order called for recovery of deferred costs within 10 years. Under phase-in plans and accounting orders from the GPSC, Georgia Power deferred and began amortizing the costs -- recovered through rates -- related to Plant Vogtle as follows:
1995 1994 1993 ------------------------------ (in millions) Deferred capacity buybacks $ - $ 10 $ 38 Amortization of deferred costs (124) (85) (74) - - ----------------------------------------------------------------- Net amortization (124) (75) (36) Effect of adoption of FASB Statement No. 109 - - 160 Deferred costs at beginning of year 432 507 383 - - ----------------------------------------------------------------- Deferred costs at end of year $308 $432 $507 =================================================================
In 1991, the GPSC ordered that the Plant Vogtle capacity buyback expense be levelized over a six-year period. The amounts deferred and not expensed in the year paid totaled $38 million in 1993. In 1995 and 1994, the amount deferred was exceeded by the amortization of amounts previously deferred by $50 million and $1 million, respectively. The projected net amortization of the deferred expense is $62 million in 1996 and $57 million in 1997.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rates used by the operating companies to calculate AFUDC during the years 1993 through 1995 ranged from a before-income-tax rate of 3.6 percent to 9.8 percent. AFUDC, net of income tax, as a percent of consolidated net income was 1.6 percent in 1995, 2.3 percent in 1994, and 1.7 percent in 1993.
Utility Plant
Utility plant is stated at original cost less regulatory disallowances. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
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
Derivative financial instruments are used by The Southern Company to manage its interest rate and foreign currency exposures. 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. Losses realized on termination of interest rate swap contracts are deferred and amortized over the terms of the related new debt agreements. At December 31, 1995, the credit risk for derivatives outstanding was not material.
The Southern Company hedges its exposure to fluctuations in interest rates by entering into swap agreements that allow the company to effectively convert its outstanding variable-rate debt into fixed rates. During 1995, the company terminated the swap contracts in place at December 31, 1994, incurring a loss on termination of approximately $32 million, which is being amortized over the life of the related new fixed-rate debt agreements. At December 31, 1995, six interest rate swap agreements were in place.
The Southern Company hedges its net investment in South Western Electricity (SWEB) through forward contracts involving Pounds Sterling. The company regularly monitors its foreign currency exposure, and ensures that hedge contract amounts do not exceed the amount of the underlying exposure. At December 31, 1995, the status of outstanding derivative contracts was as follows:
Year Of Maturity or Notional Unrealized Type Termination Amount Gain (Loss) - - --------------------- -------------- --------------------------- (in millions) Interest rate swaps 1999-2006 $308 $(9) Foreign currency forwards 1996 389 - - - -----------------------------------------------------------------------
In accordance with FASB Statement No. 107, Disclosure About Fair Value of Financial Instruments, The Southern Company's financial instruments that the carrying amount did not approximate fair value at December 31 were as follows:
Carrying Fair Amount Value -------------------------- (in millions) Long-term debt: At December 31, 1995 $8,668 $8,935 At December 31, 1994 7,674 7,373 Preferred securities: At December 31, 1995 100 114 - - -----------------------------------------------------------------
The fair value for long-term debt and preferred securities were based on either closing market price or closing price of comparable instruments.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
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, The Southern 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 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 ----------------------- 1995 1994 ----------------------- (in millions) Actuarial present value of benefit obligation: Vested benefits $2,643 $1,593 Non-vested benefits 97 68 - - ------------------------------------------------------------------ Accumulated benefit obligation 2,740 1,661 Additional amounts related to projected salary increases 705 638 - - ------------------------------------------------------------------ Projected benefit obligation 3,445 2,299 Less: Fair value of plan assets 4,725 3,171 Unrecognized net gain (1,025) (789) Unrecognized prior service cost 60 64 Unrecognized transition asset (126) (139) - - ------------------------------------------------------------------ Prepaid asset recognized in the Consolidated Balance Sheets $ 189 $ 8 ==================================================================
Postretirement Benefits ---------------------------- 1995 1994 ---------------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $394 $375 Employees eligible to retire 63 40 Other employees 392 459 - - ------------------------------------------------------------------ Accumulated benefit obligation 849 874 Less: Fair value of plan assets 205 140 Unrecognized net loss (gain) 85 3 Unrecognized prior service cost (4) - Unrecognized transition obligation 292 500 - - ------------------------------------------------------------------ Accrued liability recognized in the Consolidated Balance Sheets $271 $231 ==================================================================
In 1995, the system companies announced a cost sharing program for postretirement benefits. The program establishes limits on amounts the companies
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
will pay to provide future retiree postretirement benefits. This change reduced the 1995 accumulated postretirement benefit obligation by approximately $186 million.
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993 -------------------------------- Discount 7.3% 8.0% 7.5% Annual salary increase 4.8 5.5 5.0 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 9.8 percent for 1995, decreasing gradually to 5.3 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, 1995, by $73 million and the aggregate of the service and interest cost components of the net retiree cost by $16 million.
Components of the plans' net costs are shown below:
Pension ----------------------------- 1995 1994 1993 ----------------------------- (in millions) Benefits earned during the year $ 79 $ 77 $ 76 Interest cost on projected benefit obligation 193 160 156 Actual (return) loss on plan assets (730) 75 (432) Net amortization and deferral 412 (351) 186 - - -------------------------------------------------------------------- Net pension cost (income) $ (46) $(39) $(14) ====================================================================
Of the above net pension income, $30 million in 1995, $29 million in 1994, and $9 million in 1993 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits --------------------------- 1995 1994 1993 --------------------------- (in millions) Benefits earned during the year $ 28 $ 31 $ 27 Interest cost on accumulated benefit obligation 67 64 56 Amortization of transition obligation 27 27 28 Actual (return) loss on plan assets assets (23) 2 (12) Net amortization and deferral 12 (10) 5 - - ------------------------------------------------------------------ Net postretirement costs $111 $114 $104 ==================================================================
Of the above net postretirement costs, $78 million in 1995, $77 million in 1994, and $64 million in 1993 were charged to operating expenses. In addition, $11 million in 1995, $18 million in 1994, and $21 million in 1993 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 $42 million, $112 million, and $35 million for the years 1995, 1994, and 1993, 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 $56 million at December 31, 1995.
3. LITIGATION AND REGULATORY MATTERS
Stockholder Suit
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 The 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 seeks damages -- including treble damages pursuant to RICO -- in an unspecified amount, which if awarded, would be payable to The Southern Company. The plaintiffs' amended complaint was dismissed by the court in March 1992. The court ruled the plaintiffs had failed to present
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
adequately their allegation that The 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. The plaintiffs once again have filed an appeal. This action is still pending.
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, 1995, Georgia Power had recorded approximately $4 million in expenses associated with the site. While Georgia Power believes that the total amount of costs required for the cleanup of this site may be substantial, it is unable at this time to estimate either such total or the portion for which Georgia Power may be ultimately responsible. However, based on the nature and extent of Georgia Power's activities relating to the site, management believes that the company's portion of these costs should not be material.
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 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, 1995, Georgia Power's net investment in the plant was approximately $190 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. Any change in the rate of return on common equity that may require refunds as a result of this proceeding would be substantially for the period beginning in July 1991 and ending in October 1992.
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. The second period under review for possible refunds was substantially from October 1994 through December 1995. 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, and refunds were ordered, the amount of refunds could range up to approximately $120 million at December 31, 1995. However, management believes that rates are not excessive and that refunds are not justified.
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.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
In June 1995, the APSC issued a rate order granting Alabama Power's request for gradual adjustments to move toward parity among customer classes. This order also calls for a moratorium on any periodic retail rate increases (but not decreases) until July 2001.
In December 1995, the APSC issued an order authorizing Alabama Power to reduce balance sheet items -- such as plant and deferred charges -- at any time the company's actual base rate revenues exceed the budgeted revenues. In accordance with this order, Alabama Power reduced the unamortized balance of premium on reacquired debt by $10 million in 1995.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
Georgia Power Retail Rate Plan
On February 16, 1996, the GPSC approved a rate plan recommended by the GPSC staff that concludes the GPSC's review of Georgia Power's earnings initiated in early 1995 and addressed the company's proposed alternative retail rate plan. Under the three-year plan, effective January 1, 1996, Georgia Power's earnings will be 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 accelerate the depreciation of electric plant. At its option, Georgia Power may also accelerate amortization or depreciation of assets while within the allowed return on common equity range. The company is required to absorb cost increases of approximately $29 million annually during the plan's three-year operation, including $14 million annually of accelerated depreciation of electric plant. During the plan's operation, Georgia Power will not file for a general base rate increase unless its projected retail return on 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 rate plan or adopt a different one.
Georgia Power 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 Georgia Power's costs incurred in connection with demand-side conservation programs were unlawful. The judge held that the GPSC lacked statutory authority to approve such rate riders except through general rate case proceedings and that those procedures had not been followed. Georgia Power suspended collection of the demand-side conservation costs and appealed the court's decision to the Georgia Court of Appeals. In December 1993, the GPSC approved Georgia Power's request for an accounting order allowing Georgia Power to defer all current unrecovered and future costs related to these programs, pending the resolution of the recovery of such costs.
After the Georgia Court of Appeals upheld the legality of the rate riders, Georgia Power resumed collection under the riders in December 1994. In August 1995, the GPSC ordered Georgia Power to discontinue the demand-side conservation programs by the end of 1995. However, Georgia Power's rate riders will continue in effect until costs deferred are collected. Under the new retail rate plan, approved February 16, 1996, Georgia Power will expense approximately $29 million of deferred program costs over a three-year period that will not be recovered under the rate riders.
4. CONSTRUCTION PROGRAM
The system companies are engaged in continuous construction programs, currently estimated to total some $1.5 billion in 1996, $1.4 billion in 1997, and $1.3 billion in 1998. These estimates include AFUDC of $22 million in 1996, $22 million in 1997, and $25 million in 1998. 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, 1995, significant purchase commitments were outstanding in connection with the construction program. The operating companies do not have any new baseload generating plants under construction. However, within the service area, the construction of combustion turbine peaking units of approximately 600 megawatts is planned to be completed by 1998. In addition, significant construction will continue related to transmission and distribution facilities and the upgrading and extension of the useful lives of generating plants.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
See Management's Discussion and Analysis under "Environmental Matters" for information on the impact of the Clean Air Act Amendments of 1990 and other environmental matters.
5. FINANCING, INVESTMENTS, AND COMMITMENTS
General
The Southern Company may require additional equity capital in 1996. The amount and timing of additional equity capital to be raised in 1996 -- as well as in subsequent years -- will be contingent on The Southern Company's investment opportunities. Equity capital can be provided from any combination of public offerings, private placements, or the company's stock plans.
The operating companies' construction programs are expected to be financed primarily from internal sources. Short-term debt is often utilized and the amounts available are discussed below. The companies may issue additional long-term debt and preferred stock primarily for the purposes of debt maturities and for redeeming higher-cost securities if market conditions permit.
Southern Electric Investments
Southern Electric has substantial investments in production and delivery facilities in the United States and various international markets. The most recent acquisition was SWEB, and for additional information see Note 14. Southern Electric's total assets were $5.0 billion at December 31, 1995. The consolidated financial statements reflect investments in majority-owned or controlled subsidiaries on a consolidated basis and other investments on an equity basis.
Bank Credit Arrangements
At the beginning of 1996, unused credit arrangements with banks totaled $2.8 billion, of which approximately $1.5 billion expires at various times during 1996 and 1997; $16 million expires in February 1998; $73 million expires in May 1998; $400 million expires in June 1998; $300 million expires in July 1998; $300 million expires in November 1998; and $56 million expires in December 1998. Also, $136 million expires in the years 1999 through 2002.
Georgia Power's revolving credit agreements of $60 million, all of which remained unused as of December 31, 1995, expire May 1, 1998. During the term of these agreements, Georgia Power may convert 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 Georgia Power's option. In connection with these credit arrangements, Georgia Power agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks.
Gulf Power's revolving credit agreements of $20 million, of which $13 million remained unused as of December 31, 1995, expire May 31, 1998. These agreements allow short-term and/or term borrowings with various terms and conditions regarding repayment. In connection with these credit arrangements, Gulf Power agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks.
The $400 million expiring June 30, 1998, is under revolving credit arrangements with several banks that provide The Southern Company, Alabama Power, and Georgia Power up to the total credit amount of $400 million. To provide liquidity support to commercial paper programs, $100 million, $135 million, and $165 million available credit are currently dedicated to the exclusive use of The Southern Company, Alabama Power, and Georgia Power, respectively. During the term of these agreements, 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.
The Southern Company has $300 million of revolving credit agreements expiring July 1, 1998, and $300 million of revolving credit agreements expiring November 30, 1998, all of which remained unused at December 31, 1995. 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 Southern Company's option. In connection with these credit arrangements, The Southern Company agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Mississippi Power's revolving credit agreements of $40 million, all of which remained unused as of December 31, 1995, expire December 1, 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 Mississippi Power's option. In connection with these credit arrangements, Mississippi Power agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks.
Savannah Electric's revolving credit arrangements of $20 million, of which $16 million remained unused as of December 31, 1995, expire December 31, 1998. These agreements allow short-term borrowings to be converted into terms 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 Savannah Electric's option. In connection with these credit arrangements, Savannah Electric agrees to pay commitment fees based on the unused portions of the commitments.
Southern Electric's revolving credit agreements of $212 million, of which $151 million remained unused as of December 31, 1995, expire at various times from 1998 through 2002. These agreements allow for short-term borrowings with various terms and conditions. These agreements require payment of commitment fees based on the unused portions of the commitments.
A portion of the $2.8 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, 1995, the amount of credit lines allocated was $692 million.
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.
In addition, the companies from time to time borrow under uncommitted lines of credit with banks and in the case of The 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 The Southern Company's subsidiaries is organized as a legal entity, separate, and apart from The 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 The Southern Company or any of its subsidiaries.
Fuel and Purchase Power Commitments
To supply a portion of the fuel requirements of the generating plants, The Southern Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Also, The Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated long-term obligations at December 31, 1995, were as follows:
Purchased Year Fuel Power - - ----------- ----------------------------- (in millions) 1996 $ 1,914 $ 495 1997 1,656 427 1998 1,482 155 1999 1,093 161 2000 728 166 2001 and thereafter 6,078 1,943 - - ------------------------------------------------------------- Total commitments $12,951 $3,347 =============================================================
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Operating Leases
The Southern Company has operating lease agreements with various terms and expiration dates. These expenses totaled $17 million, $15 million, and $11 million for 1995, 1994, and 1993, respectively. At December 31, 1995, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts - - -------- ---------------- (in millions) 1996 $ 22 1997 20 1998 19 1999 19 2000 20 2001 and thereafter 252 - - --------------------------------------------------------------- Total minimum payments $352 ===============================================================
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.
In 1995, Georgia Power completed the sale of Unit 4 of Plant Scherer to Florida Power & Light Company (FP&L) and Jacksonville Electric Authority (JEA). FP&L owns approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia Power operates and maintains the unit.
At December 31, 1995, 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% $3,295 $730 Plant Hatch (nuclear) 50.1 842 394 Plant Miller (coal) Units 1 and 2 91.8 712 281 Plant Scherer (coal) Units 1 and 2 8.4 112 39 Plant Wansley (coal) 53.5 297 132 Rocky Mountain (pumped storage) 25.4 200 10 - - ------------------------------------------------------------------
In 1994, Georgia Power and FPC entered into a joint ownership agreement regarding the Intercession City combustion turbine unit. The unit is scheduled to be in commercial operation by the end of 1996, and will be constructed, operated, and maintained by FPC. Georgia Power will have an approximate interest of 33 percent in the 150-megawatt unit, with retention of 100 percent of the capacity from June through September. FPC will have the capacity the remainder of the year. Georgia Power's investment in the unit at completion is estimated to be $14 million.
Alabama Power and Georgia Power have contracted to operate and maintain the jointly owned facilities -- except for the Rocky Mountain project and Intercession City -- as agents for their respective co-owners. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the Consolidated Statements of Income.
7. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. 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
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
generally sold at cost under these agreements, revenues from capacity sales primarily affect profitability. The capacity revenues have been as follows:
Unit Other Year Power Long-Term Total ---- ------------------------------------ (in millions)
1995 $237 $ - $237 1994 257 19 276 1993 312 38 350
In 1994, long-term non-firm power of 200 megawatts was sold to FPC under a contract that expired at year-end. In January 1995, the amount of unit power sales to FPC increased by 200 megawatts.
Unit power from specific generating plants is currently being sold to FP&L, FPC, JEA, and the city of Tallahassee, Florida. Under these agreements, approximately 1,600 megawatts of capacity is scheduled to be sold 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 -- until the expiration of the contracts in 2010.
8. INCOME TAXES
Effective January 1, 1993, The Southern Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption resulted in the recording of additional deferred income taxes and related regulatory assets and liabilities. At December 31, 1995, the tax- related regulatory assets and liabilities were $1.4 billion and $936 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:
1995 1994 1993 --------------------------- (in millions) Total provision for income taxes: Federal -- Currently payable $567 $598 $421 Deferred -- current year 184 67 224 -- reversal of prior years (111) (75) (51) Deferred investment tax credits 1 - (20) - - ------------------------------------------------------------------- 641 590 574 - - ------------------------------------------------------------------- State -- Currently payable 90 86 64 Deferred -- current year 26 15 39 -- reversal of prior years (12) (11) (3) - - ------------------------------------------------------------------- 104 90 100 - - ------------------------------------------------------------------- International 24 5 3 - - ------------------------------------------------------------------- Total 769 685 677 Less income taxes charged (credited) to other income (36) (26) (57) - - ------------------------------------------------------------------- Federal and state income taxes charged to operations $805 $711 $734 ===================================================================
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:
1995 1994 ----------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $2,795 $2,637 Property basis differences 2,175 1,647 Deferred plant costs 100 141 Other 247 271 - - ------------------------------------------------------------------- Total 5,317 4,696 - - ------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 107 104 Other property basis differences 273 278 Deferred costs 118 79 Pension and other benefits 66 63 Other 192 225 - - ------------------------------------------------------------------- Total 756 749 - - ------------------------------------------------------------------- Net deferred tax liabilities 4,561 3,947 Portion included in current assets, net 50 60 - - ------------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheet $4,611 $4,007 ===================================================================
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 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 $38 million in 1995, $42 million in 1994, and $36 million in 1993. At December 31, 1995, 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:
1995 1994 1993 ------------------------------ Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.3 3.7 Non-deductible book depreciation 1.6 1.8 1.9 Difference in prior years' deferred and current tax rate (1.1) (1.5) (1.3) Other 0.3 0.3 (1.1) - - ---------------------------------------------------------------------- Effective income tax rate 39.2% 38.9% 38.2% ======================================================================
The 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
Stock Distribution
In January 1994, The Southern Company board of directors authorized a two-for-one common stock split in the form of a stock distribution for each share held as of February 7, 1994. For all reported common stock data, the number of common shares outstanding and per share amounts for earnings, dividends, and market price reflect the stock distribution.
Shares Reserved
At December 31, 1995, a total of 69 million shares was reserved for issuance pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Executive Stock Option Plan.
Executive Stock Option Plan
The Southern Company's Executive Stock Option Plan authorizes the granting of non-qualified stock options to key employees of The Southern Company, including officers. As of December 31, 1995, some 200 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 price of options granted to date has been at the fair market value of the shares on the date 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 1994 and 1995 is summarized below:
Shares Average Subject Option Price To Option Per Share ----------------------------------- Balance at December 31, 1993 1,364,810 $16.77 Options granted 446,443 18.88 Options canceled -- -- Options exercised (74,649) 14.81 - - --------------------------------------------------------------------- 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 ===================================================================== Shares reserved for future grants: At December 31, 1993 3,714,444 At December 31, 1994 3,268,001 At December 31, 1995 2,114,915 - - --------------------------------------------------------------------- Options exercisable: At December 31, 1994 793,989 At December 31, 1995 831,227 - - ---------------------------------------------------------------------
Common Stock Dividend Restrictions
The income of The Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 1995, consolidated retained earnings included $3.1 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.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
10. PREFERRED SECURITIES
In December 1994, Georgia Power Capital, L.P., of which Georgia Power is the sole general partner, issued $100 million of 9 percent mandatorily redeemable preferred securities. The sole asset of Georgia Power Capital is $103 million aggregate principal amount of Georgia Power's 9 percent Junior Subordinated Deferrable Interest Debentures due December 19, 2024. Georgia Power considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by Georgia Power of Georgia Power Capital's payment obligations with respect to the preferred securities.
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1995 1994 -------------------- (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 2000-2025 $1,466 $1,179 Variable rates (3.5% to 6.1% at 1/1/96) due 2011-2025 639 412 Non-collateralized -- 7.25% due 2003 1 1 6.75% to 10.6% due 2015-2020 277 828 5.8% due 2022 10 10 Variable rates (3.25% to 3.75% at 1/1/96) due 2019-2022 132 85 - - ---------------------------------------------------------------- 2,525 2,515 - - ---------------------------------------------------------------- Capitalized lease obligations 147 148 - - ---------------------------------------------------------------- Notes payable: 4.15% to 13% due 1995-1998 107 179 6.31% to 11% due 1999-2008 404 170 Adjustable rates (4% to 7% at 1/1/96) due 1995-1998 129 119 Adjustable rates (7.5% to 9.18% at 1/1/96) due 1999-2000 165 130 Adjustable rate (7.7 % at 1/1/96) due 2000 926 - - - ---------------------------------------------------------------- 1,731 598 - - ----------------------------------------------------- ---------- Total $4,403 $3,261 ================================================================
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.
Assets acquired under capital leases are recorded as utility plant in service, and the related obligation is classified as other long-term debt. The net book value of capitalized leases was $122 million and $126 million at December 31, 1995 and 1994, respectively. At December 31, 1995, the composite interest rates for buildings and other were 9.7 percent and 11.3 percent, respectively. Sinking fund requirements and/or serial maturities through 2000 applicable to other long-term debt are as follows: $264 million in 1996; $99 million in 1997; $42 million in 1998; $23 million in 1999; and $56 million in 2000.
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:
1995 1994 ----------------- (in millions) Bond improvement fund requirements $ 43 $ 48 Less: Portion to be satisfied by certifying property additions 18 46 Reacquired bonds - - - - ------------------------------------------------------------------ Cash sinking fund requirements 25 2 First mortgage bond maturities and redemptions 220 130 Other long-term debt maturities (Note 11) 264 97 - - ------------------------------------------------------------------ Total $509 $229 ==================================================================
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.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
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 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 $10 million and $12 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 $21 million and $24 million, respectively. The maximum replacement power assessments are $8 million for Alabama Power and $13 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.
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
14. ACQUISITION
In 1995, Southern Electric 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 preliminary estimate of the fair market value of net assets by $333 million. This amount is considered goodwill and will be amortized on a straight-line basis over 40 years. The preliminary estimate of net assets may be 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 1994, and assuming 100 percent short-term debt financing. Eventually, the short-term borrowings will be replaced by a combination of long-term debt and equity. The pro forma 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
The Southern Company's principal business segment -- or its core business -- is the five electric utility operating companies, which provide electric service in four Southeastern states. The other reportable business segment is Southern Electric, which owns and operates power production and delivery facilities in the United States and various international markets. Financial data for business segments and geographic areas are as follows:
Business Segments
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NOTES (continued) The Southern Company and Subsidiary Companies 1995 Annual Report
Geographic Areas
II-38
II-39
II-40A
II-40B
II-41
II-42A
II-42B
II-43
II-44A
II-44B
II-44C
II-45
II-46A
II-46B
II-46C
II-47
II-48A
II-48B
II-48C
II-49
II-50A
II-50B
II-50C
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-51
Management's Report Alabama Power Company 1995 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 21, 1996
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (an Alabama corporation and wholly owned subsidiary of The Southern Company) as of December 31, 1995 and 1994, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. 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-61 through II-78) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Birmingham, Alabama February 21, 1996
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1995 net income after dividends on preferred stock was $361 million, representing a $4.6 million (1.3 percent) increase from the prior year. This improvement can be attributed to an increase in retail energy sales of 4.7 percent from 1994 levels. This was primarily due to the extreme summer weather during 1995, especially when compared to the mild weather of 1994. This improvement was partially offset by a 2.6 percent increase in operating costs.
In 1994, earnings were $356 million, representing a 2.8 percent increase from the prior year. This increase was due to lower operating expenses which decreased 3.0 percent from the previous year. This improvement was partially offset by reduced capacity sales to nonterritorial utilities. Net income was also impacted by the mild weather in 1994.
The return on average common equity for 1995 was 13.61 percent compared to 13.86 percent in 1994, and 13.94 percent in 1993.
Revenues
Total revenues for 1995 were $3.0 billion, reflecting a 3.1 percent increase from 1994. The following table summarizes the principal factors that affected operating revenues for the past three years:
Increase (Decrease) From Prior Year ---------------------------------------- 1995 1994 1993 ------------- ------------ ------------- (in thousands) Retail -- Change in base rates $ 990 $ -- $ -- Unbilled adjustment -- 28,000 -- Sales growth 18,174 45,304 24,960 Weather 54,888 (39,964) 58,536 Fuel cost recovery and other 35,235 (84,344) 96,437 --------------------------------------------------------------- Total retail 109,287 (51,004) 179,933 --------------------------------------------------------------- Sales for Resale -- Non-affiliates 15,380 (9,345) (43,686) Affiliates (37,032) (17,213) 23,887 --------------------------------------------------------------- Total sales for resale (21,652) (26,558) (19,799) Other operating revenues 1,997 5,095 635 --------------------------------------------------------------- Total operating revenues $89,632 $(72,467) $160,769 --------------------------------------------------------------- Percent change 3.1% (2.4)% 5.6% ---------------------------------------------------------------
Retail revenues of $2.5 billion in 1995 increased $109 million (4.6 percent) from the prior year, compared with a decrease of $51 million (2.1 percent) in 1994. 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. The mild weather during 1994 and lower fuel cost recovery contributed to the decrease in retail revenues from 1993. Fuel revenues, which increased in 1995, 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1995 Annual Report
contracts. Energy is generally sold at variable cost. These capacity and energy components, as well as the components of the sales to affiliated companies, were:
1995 1994 1993 ------------------------------------------- (in thousands)
Capacity $158,825 $165,063 $187,062 Energy 209,376 222,579 233,253 ---------------------------------------------------------- Total $368,201 $387,642 $420,315 ----------------------------------------------------------
Capacity revenues from non-affiliates remained relatively constant in 1995 and 1994. Capacity revenues from sales to affiliates decreased $22 million in 1994. 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 1995 and the percent change by year were as follows:
KWH Percent Change ------------------------------------------- 1995 1995 1994 1993 ------------------------------------------- (millions)
Residential 14,383 9.1% (1.7)% 9.2% Commercial 10,043 4.1 3.4 6.4 Industrial 19,863 2.0 3.2 1.8 Other 187 0.5 1.1 2.8 ---------- Total retail 44,476 4.7 3.3 5.1 Sales for resale - Non-affiliates 8,046 18.8 (5.2) (14.8) Affiliates 6,705 (20.5) 4.3 12.1 ---------- Total 59,227 2.6% 2.4% 3.0% - - -----------------------------------------------------------------
The rate of increase in 1995 retail energy sales was fostered by the impact of weather. Residential energy sales surged upward as a result of hotter-than-normal summer weather in 1995, compared with the mild summer of 1994. The gains in commercial and industrial sales reflect the strength of business and economic conditions in the company's service area.
Expenses
Total operating expenses of $2.4 billion for 1995 were up $60 million or 2.6 percent compared with 1994. The major components of this increase include $27 million in purchased power, $43 million in other operation expenses, $11 million in depreciation and amortization, and $7 million in income taxes offset by decreases in fuel costs and maintenance expenses of $10 million and $19 million, respectively.
Total operating expenses of $2.3 billion for 1994 were down 3.0 percent compared with the prior year. The decrease was mainly due to less coal-fired generation and a lower average cost of fuel consumed. Coal-fired generation decreased because it was displaced with lower cost nuclear and hydro generation.
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:
-------------------------- 1995 1994 1993 ------------------------- Total generation (billions of kilowatt-hours) 58 57 55 Sources of generation (percent) -- Coal 73 68 70 Nuclear 19 23 22 Hydro 8 9 8 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.71 1.92 2.11 Nuclear 0.50 0.49 0.51 Total 1.48 1.56 1.73 - - -------------------------------------------------------------- Note: Oil & Gas comprise less than 0.5% of generation.
Fuel expense decreased in 1995 by $10 million or 1.3 percent. This decrease resulted from lower average cost of fuel consumed. Fuel expense decreased in 1994 by $75 million (8.6 percent) from the previous year. This decrease is attributable to the increase in availability of nuclear and hydro generation and a decrease in the cost of fuel.
The increase in purchased power is primarily attributable to the exceptionally hot summer weather. Purchased power consists primarily of purchases from the affiliates of the Southern electric system. Purchased power
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1995 Annual Report
transactions among the company and its affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at each company. KWH purchases from affiliates increased 18 percent from the prior year.
Other operation expenses increased 9.4 percent in 1995 following a 2.5 percent decrease in 1994. This increase over 1994 is primarily attributable to the 1995 expenses not reflecting the positive impact of the amortization of the Gulf States Utilities settlement which expired in 1994.
The decrease in maintenance expenses for 1995 reflects the establishment in September 1994 of a Natural Disaster Reserve. This also caused the increase in 1994 maintenance expenses over 1993. See Note 1 to the financial statements under "Natural Disaster Reserve" for additional information.
Depreciation and amortization expense increased 3.6 percent in 1995. This increase reflects additions to utility plant. The amount for 1994 was virtually unchanged from the previous year because of lower average depreciation rates effective January 1994 and offsetting growth in depreciable plant in service.
Income tax expense increased 3.0 percent and 8.2 percent in 1995 and 1994, respectively. These increases are primarily attributable to higher taxable income.
The company contributed $11.5 million to the Alabama Power Foundation, Inc. in 1995, which represents a decrease of $2.0 million from the previous year. The Foundation makes distributions to qualified entities which are organized exclusively for charitable, educational, literary, and scientific purposes.
Total net interest charges and preferred stock dividends rose in 1995 to $265 million, an increase of 12.2 percent. 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 an APSC order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details. The decline in net interest charges in 1994 by $23 million (9.0 percent) reflects the benefits from refinancing.
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 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 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
II-56
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1995 Annual Report
marketers and brokers. The company is aggressively working to maintain and expand its share of wholesale sales in the Southeastern power markets.
Although the Energy Act does not require transmission access to retail customers, retail wheeling initiatives are rapidly evolving and becoming very prominent issues in several states. New federal legislation is being discussed, and legislation allowing customer choice has already been introduced in Florida and Georgia. In order to address these initiatives, numerous questions must be resolved, with the most complex ones relating to transmission pricing and recovery of stranded investments. As the initiatives become a reality, the structure of the utility industry could radically change. Therefore, 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. Conversely, being the low-cost producer could provide significant opportunities to increase market share and profitability by seeking new markets that evolve with the changing regulation.
The addition of four combustion turbine generating units in 1996 will increase related operation and maintenance expenses and depreciation expenses. These additions are to ensure reliable service to its customers during critical peak times.
Rates to retail customers served by the company are regulated by the Alabama Public Service Commission (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 regulatory 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 increase. Because of the company's current ability to recover closure and removal costs through rates, these changes should 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.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount for an asset may not be recoverable. This statement also imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. The company adopted the new rules January 1, 1996, with no material effect on the financial statements. However, this conclusion may change in the future as competitive factors influence wholesale and retail pricing in the utility industry.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1995. 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 $552 million in 1995. 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 45.0 percent in 1995, compared with 45.9 percent in 1994, and 46.5 percent in 1993.
In 1995, the company issued through public authorities, $131.5 million of pollution control revenue refunding bonds. Composite financing rates as of year-end for 1993 through 1995 were as follows:
1995 1994 1993 -------------------------------- Composite interest rate on long-term debt 7.02% 7.39% 7.35% Composite dividend rate on preferred stock 6.04% 6.23% 5.80% ----------------------------------------------------------------
The company's current securities ratings are as follows:
Duff & Standard Phelps Moody's & Poor's ---------------------------------- First Mortgage Bonds A+ A1 A+ Preferred Stock A a2 A ------------------------------------------------------------
Capital Requirements
Capital expenditures are estimated to be $491 million for 1996, $446 million for 1997, and $479 million for 1998. The total is $1.4 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 does not have any baseload generating plants under construction, and current energy demand forecasts do not require any additional baseload generating units until well into the future. However, the addition of combustion turbine peaking units of approximately 320 megawatts of capacity is planned in 1996 to meet increased peak-hour demands. 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 $110 million will be required by the end of 1998 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 -- has significantly impacted the Southern electric system. 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 in the Southern electric system. As a result of The 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1995 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 method for issuing allowances is based on the fossil fuel consumed from 1985 through 1987 for each affected generating unit. Emission allowances are transferable and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. The Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
The 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. Compliance with nitrogen oxide emission limits was achieved by the installation of new control equipment at 22 of the original 28 affected generating units. Construction expenditures for Phase I compliance totaled approximately $320 million through 1995 for The Southern Company, of which the company's portion was approximately $32 million.
For Phase II sulfur dioxide compliance, The Southern Company could use emission allowances banked during Phase I, increase fuel switching, install flue gas desulfurization equipment at selected plants, and/or purchase more allowances, depending on the price and availability of allowances. Also, in Phase II, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as required to meet Phase II limits. Therefore, during the period 1996 to 2000, current compliance strategy could require total estimated construction expenditures of approximately $150 million for The Southern Company, of which the company's portion is approximately $96 million. 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.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The EPA is scheduled to submit a report to Congress on the results of this study during 1996. The report will include a decision on whether additional regulatory control of these substances is warranted. Compliance with any new control standards could result in significant additional costs. The impact of new standards -- if any -- will depend on the development and implementation of applicable regulations.
The EPA is evaluating the need to revise the ambient air quality standards for particulate matter and ozone. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In 1996, the EPA may issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1995 Annual Report
additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
The company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the company could incur costs to clean up properties. The company conducts studies to determine the extent of any required cleanup costs and has recognized in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of The Southern Company's operations. The full impact of these requirements cannot be determined at this time, pending the development and implementation of applicable regulations.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect the Southern electric system. 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."
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NOTES TO FINANCIAL STATEMENTS Alabama Power Company 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the company) is a wholly owned subsidiary of The Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Electric International (Southern Electric), 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 The 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 Electric 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 The Southern Company's nuclear power plants. Southern Development develops new business opportunities related to energy products and services.
The Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both The 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:
1995 1994 ----------------------- (in thousands) Deferred income taxes $436,837 $451,886 Premium on reacquired debt 89,967 101,620 Department of Energy assessments 40,282 42,996 Vacation pay 29,458 20,442 Work force reduction costs 48,402 3,664 Deferred income tax credits (386,038) (405,256) Natural disaster reserve (17,959) (28,750) Other, net 39,172 45,956 ================================================================ Total $280,121 $232,558 ================================================================
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.
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NOTES (continued) Alabama Power Company 1995 Annual Report
The company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1995, 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 $54 million in 1995, $65 million in 1994, and $62 million in 1993. 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 2012 and 2014 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, 1995, under this law to be approximately $40 million. This obligation is recognized in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2 percent in 1995 and 1994, and 3.3 percent in 1993. 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 set periods of time as 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, 1995, for Plant Farley were as follows:
Plant Farley ---------------- 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 ===========================================================
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NOTES (continued) Alabama Power Company 1995 Annual Report
(in millions) Amount expensed in 1995 $ 18 -----------------------------------------------------------
Accumulated provisions: Balance in external trust funds $108 Balance in internal reserves 49 =========================================================== Total $157 ===========================================================
Assumed in ultimate costs: Inflation rate 4.5% Trust earning rate 7.0 -----------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity -- sinking fund -- method as approved by the APSC. The decommissioning costs approved for ratemaking are $578 million for Plant Farley.
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making estimates.
Income Taxes
The company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Allowance For Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rate used to determine the amount of allowance was 7.1 percent in 1995, 7.9 percent in 1994, and 7.8 percent in 1993. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 1.7 percent in 1995 and 1.5 percent in both 1994 and 1993.
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
In accordance with FASB Statement No. 107, Disclosure About Fair Value of Financial Instruments, the company's only financial instrument for which the carrying amount did not approximate fair value at December 31 was as follows:
Long-Term Debt ------------------------- Carrying Fair Year Amount Value ----------- ---------- (in millions)
1995 $2,451 $2,577 1994 2,446 2,323 ------------------------------------------------------------
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 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. As of December 31, 1995, the accumulated provision amounted to $18.0 million. This balance is down from the December 31, 1994 balance of $28.8 million, due to charges related primarily to Hurricane Opal, somewhat offset by a $10 million accrual to partially replenish the reserve. Regulatory treatment allows the
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NOTES (continued) Alabama Power Company 1995 Annual Report
company to accrue $250 thousand per month, until the maximum accumulated provision of $32 million is attained. However, in December 1995, the APSC approved higher accruals to restore the reserve to its authorized level whenever the balance in the reserve declines below $22.4 million.
2. RETIREMENT BENEFITS
Pension Plan
The company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. Benefits are based on one of the following formulas: years of service and final average pay or years of service and a flat-dollar benefit. Primarily, 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 ----------------------- 1995 1994 ------------- --------- (in millions) Actuarial present value of benefit obligations: Vested benefits $ 604 $ 522 Non-vested benefits 25 18 - - ------------------------------------------------------------------ Accumulated benefit obligation 629 540 Additional amounts related to projected salary increases 173 174 - - ------------------------------------------------------------------ Projected benefit obligation 802 714 Less: Fair value of plan assets 1,256 1,059 Unrecognized net gain (331) (251) Unrecognized prior service cost 21 23 Unrecognized transition asset (45) (51) - - ------------------------------------------------------------------ Prepaid asset recognized in the Balance Sheets $ 99 $ 66 ==================================================================
Postretirement Benefits ---------------------- 1995 1994 ---------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $ 103 $ 96 Employees eligible to retire 31 22 Other employees 104 119 ----------------------------------------------------------- Accumulated benefit obligation 238 237 Less: Fair value of plan assets 89 61 Unrecognized net loss 23 - Unrecognized transition obligation 72 120 ----------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 54 $ 56 ===========================================================
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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NOTES (continued) Alabama Power Company 1995 Annual Report
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993 -------------------------------
Discount 7.3% 8.0% 7.5% Annual salary increase 4.8 5.5 5.0 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 9.8 percent for 1995, decreasing gradually to 5.3 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, 1995, by $20 million and the aggregate of the service and interest cost components of the net retiree cost by $4 million.
Components of the plans' net income are shown below:
Pension -------------------------------------------------------------- 1995 1994 1993 ----------------------------- (in millions) Benefits earned during the year $ 21.2 $ 20.8 $ 20.6 Interest cost on projected benefit obligation 54.3 51.2 50.4 Actual (return) loss on plan assets (236.3) 23.5 (146.3) Net amortization and deferral 136.9 (116.2) 63.3 ============================================================== Net pension income $(23.9) $(20.7) $(12.0) ==============================================================
Of the above net pension income, $(17.1) million in 1995, $(15.7) million in 1994, and $(8.9) million in 1993 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits -------------------- 1995 1994 1993 -------------------- (in millions)
Benefits earned during the year $ 7 $ 8 $ 7 Interest cost on accumulated benefit obligation 18 18 16 Amortization of transition obligation 7 6 6 Actual (return) loss on plan assets (10) 1 (5) Net amortization and deferral 5 (4) 2 ============================================================= Net postretirement costs $ 27 $ 29 $ 26 =============================================================
Of the above net postretirement costs recorded, $22.7 million in 1995, $23 million in 1994, and $22 million in 1993 were charged to operating expenses and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The company has incurred additional costs for work force reduction programs. The costs related to these programs were $14.3 million, $8.2 million and $16.1 million for the years 1995, 1994 and 1993, 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 $48.4 million at December 31, 1995.
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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NOTES (continued) Alabama Power Company 1995 Annual Report
also calls for a moratorium on any periodic retail rate increases (but not decreases) until July 2001.
In December 1995, the APSC issued an order authorizing the company to reduce balance sheet items -- such as plant and deferred charges -- at any time the company's actual base rate revenues exceed the budgeted revenues. In accordance with this order, the company reduced the unamortized balance of Premium on reacquired debt by $10 million in 1995.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
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. Any change in the rate of return on common equity that may require refunds as a result of this proceeding would be substantially for the period beginning in July 1991 and ending in October 1992.
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. The second period under review for possible refunds was substantially from October 1994 through December 1995. 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, and refunds were ordered, the amount of refunds could range up to approximately $120 million at December 31, 1995 for the Southern Company, of which the company's portion would be approximately $53 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 $491 million in 1996, $446 million in 1997, and $479 million in 1998. The estimates include AFUDC of $7 million in 1996, $6 million in 1997, and $9 million in 1998. 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, 1995, significant purchase commitments were outstanding in connection with the construction program. The company does not have any new baseload generating plants under construction. However, the construction of combustion turbine peaking units of approximately 320 megawatts is planned to be completed in 1996. In addition, significant construction will continue related to transmission and distribution facilities and the upgrading and extension of the useful lives of generating plants.
5. FINANCING, INVESTMENT, AND COMMITMENTS
General
To the extent possible, the company's construction program is expected to be financed primarily from internal sources. Short-term debt will be utilized at appropriate levels. The amounts available are discussed below. The company may issue additional long-term debt and preferred stock for the purposes of debt maturities, redeeming higher-cost securities, and meeting additional capital requirements.
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NOTES (continued) Alabama Power Company 1995 Annual Report
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 The 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 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 The 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, 1998. 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. 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 $353.5 million which expire at various times during 1996 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, 1995, the company had regulatory approval to have outstanding up to $530 million of short-term borrowings. In February 1996, such regulatory approval was increased to $750 million.
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, 1995, were as follows:
Year Amounts - - ---- -------------- (in millions)
1996 $ 866 1997 852 1998 853 1999 672 2000 402 2001 - 2013 3,790 ========================================================= Total commitments $7,435 =========================================================
Operating Leases
The company has entered into coal rail car rental agreements with various terms and expiration dates. At December 31, 1995, estimated minimum rental commitments for noncancellable operating leases were as follows:
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NOTES (continued) Alabama Power Company 1995 Annual Report
Year Amounts - - ---- -------------------- (in millions) 1996 $ 2.8 1997 2.8 1998 2.9 1999 2.9 2000 2.9 2001 and thereafter 56.5 =============================================================== Total minimum payments $70.8 ===============================================================
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 1,019,680 kilowatts, 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 $71 million in 1995, $74 million in 1994 and $86 million in 1993, 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, 1995, the capitalization of SEGCO consisted of $54 million of equity and $78 million of long-term debt on which the annual interest requirement is $5.0 million. SEGCO paid dividends totaling $7.6 million in 1995, $11.6 million in 1994, and $11.3 million in 1993, of which one-half of each was paid to the company. SEGCO's net income was $8.1 million, $7.2 million, and $8.3 million for 1995, 1994 and 1993, respectively.
The company's percentage ownership and investment in jointly-owned generating plants at December 31, 1995, 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 $ 41 Plant Miller Units 1 and 2 712 281 - - -------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
General
The company and the operating affiliates of The 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, revenues from capacity sales primarily affect profitability. The company's capacity revenues have been as follows:
Unit Other Year Power Long-Term Total ---------------------------------------------------------- (in millions) 1995 $ 157 $ - $ 157 1994 152 7 159 1993 144 15 159 ----------------------------------------------------------
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,
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NOTES (continued) Alabama Power Company 1995 Annual Report
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 -- 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, 1995, $137.5 million of such bonds was held by the escrow agent under the contracts.
8. INCOME TAXES
Effective January 1, 1993, the company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption resulted in the recording of additional deferred income taxes and related regulatory assets and liabilities. At December 31, 1995, the tax-related regulatory assets and liabilities were $437 million and $386 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:
1995 1994 1993 -------------------------------- (in thousands) Total provision for income taxes: Federal -- Currently payable $166,105 $219,494 $149,680 Deferred -- current year 43,493 (48,153) 9,636 reversal of prior years (15,817) 15,932 19,653 Deferred investment tax credits (75) (1) (2,106) ---------------------------------------------------------------- 193,706 187,272 176,863 ---------------------------------------------------------------- State -- Currently payable 18,108 20,565 14,297 Deferred -- current year 5,117 (4,067) 1,898 reversal of prior years (91) 3,676 3,913 ---------------------------------------------------------------- 23,134 20,174 20,108 ---------------------------------------------------------------- Total 216,840 207,446 196,971 Less income taxes credited to other income (14,142) (16,834) (10,239) ---------------------------------------------------------------- Federal and state income taxes charged to operations $230,982 $224,280 $207,210 ================================================================
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
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NOTES (continued) Alabama Power Company 1995 Annual Report
1995 1994 - - -------------------------------------------------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $ 780 $734 Property basis differences 491 513 Premium on reacquired debt 31 38 Fuel clause underrecovered 5 4 Other 37 26 - - -------------------------------------------------------------- Total 1,344 1,315 - - -------------------------------------------------------------- Deferred tax assets: Capacity prepayments 35 36 Other deferred costs 26 27 Postretirement benefits 25 24 Accrued nuclear outage costs - 7 Unbilled revenue 13 13 Other 43 44 - - -------------------------------------------------------------- Total 142 151 - - -------------------------------------------------------------- Net deferred tax liabilities 1,202 1,164 Portion included in current assets (liabilities), net (10) 17 - - -------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,192 $1,181 ==============================================================
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 $12 million in 1995 and $13 million in 1994 and 1993. At December 31, 1995, 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:
1995 1994 1993 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.5 2.2 2.3 Non-deductible book depreciation 1.6 1.6 1.6 Differences in prior years' deferred and current tax rates (1.8) (2.9) (1.6) Other (1.4) (0.7) (2.9) ============================================================== Effective income tax rate 35.9% 35.2% 34.4% ==============================================================
The 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. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows: 1995 1994 -------------------------- (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 (5.0% to 6.0% at 1/1/96) due 2015-2017 89,800 89,800 Non-collateralized - 7.25% due 2003 1,000 1,000 7.4% to 9.375% due 2014-2016 21,000 152,500 5.8% due 2022 9,800 9,800 Variable rates (5.3% to 6.0% at 1/1/96) due 2022 131,500 - - - ------------------------------------------------------------- 476,140 476,140 Capitalized lease obligations 8,963 9,754 ============================================================= Total $485,103 $485,894 =============================================================
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.
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NOTES (continued) Alabama Power Company 1995 Annual Report
The company has capitalized certain office building leases and a street light lease. In December 1994, the company discontinued capital leases pertaining to nuclear fuel.
The net book value of capitalized leases included in utility plant in service was $5.6 million and $6.2 million at December 31, 1995 and 1994, respectively. The estimated aggregate annual maturities of other long-term debt through 2000 are as follows: $0.9 million in 1996, $1.0 million in 1997, $1.0 million in 1998, $1.2 million in 1999 and $1.1 million in 2000.
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 at December 31 is as follows:
1995 1994 ---------------------- (in thousands) Bond improvement fund requirements $20,047 $ 20,047 Less: Portion to be satisfied by certifying property additions - 20,047 ------------------------------------------------------------ Cash sinking fund requirements $20,047 $ - First mortgage bond maturities and redemptions 63,750 - Other long-term debt maturities (Note 9) 885 796 ============================================================ Total $84,682 $ 796 ============================================================
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 1996 requirement of $20.0 million was satisfied by the deposit of cash in 1996. Also in 1996 are first mortgage bond maturities and redemptions of $64 million and maturities of $885 thousand consisting primarily of capitalized office building leases and a street light lease.
11. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (Act), the company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $8.9 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums which could be assessed, after a nuclear incident, against all owners of nuclear reactors. 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 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 $10 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
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NOTES (continued) Alabama Power Company 1995 Annual Report
that policy. The maximum annual assessments per incident under current policies for the company would be $21 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.
12. COMMON STOCK DIVIDEND RESTRICTIONS
The company's first mortgage bond indenture contains various common stock dividend restrictions that remain in effect as long as the bonds are outstanding. At December 31, 1995, retained earnings of $807 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.
13. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1995 and 1994 are as follows:
Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock ---------------- ---------------------------------------------- (in thousands)
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
March 1994 $686,847 $128,623 $ 72,031 June 1994 759,399 162,696 98,668 September 1994 838,927 199,736 141,214 December 1994 649,969 104,949 44,425 ----------------------------------------------------------------
The company's business is influenced by seasonal weather conditions.
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ALABAMA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1995
First Mortgage Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1993 $ 60,000 4-1/2% $ 60,000 3/1/96 1993 50,000 5-1/2% 50,000 2/1/98 1992 170,000 6-3/8% 170,000 8/1/99 1993 100,000 6% 100,000 3/1/00 1992 100,000 6.85% 100,000 8/1/02 1993 125,000 7% 125,000 1/1/03 1993 175,000 6-3/4% 175,000 2/1/03 1992 175,000 7-1/4% 175,000 8/1/07 1991 100,000 9-1/4% 98,748 5/1/21 1991 150,000 8-3/4% 148,500 12/1/21 1992 200,000 8-1/2% 198,000 5/1/22 1992 100,000 8.30% 99,608 7/1/22 1993 100,000 7-3/4% 100,000 2/1/23 1993 150,000 7.45% 150,000 7/1/23 1993 100,000 7.30% 100,000 11/1/23 1994 150,000 9% 150,000 12/1/24 ============= ============== $ 2,005,000 $ 1,999,856 ============= ==============
Pollution Control Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1978 $ 5,600 7-1/4% $ 1,000 5/1/03 1986 21,000 7.40% 21,000 11/1/16 1993 12,100 Variable 12,100 8/1/17 1993 12,000 Variable 12,000 8/1/17 1993 12,000 Variable 12,000 8/1/17 1993 96,990 6.05% 96,990 5/1/23 1993 9,800 5.80% 9,800 6/1/22 1994 24,400 5-1/2% 24,400 1/1/24 1994 53,700 Variable 53,700 6/1/15 1994 101,650 6-1/2% 101,650 9/1/23 1995 50,000 Variable 50,000 5/1/22 1995 81,500 Variable 81,500 10/1/22 ============= ============== $ 480,740 $ 476,140 ============= ==============
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 ============= ==============
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ALABAMA POWER COMPANY
SECURITIES RETIRED DURING 1995
Pollution Control Bonds Principal Interest Series Amount Rate - - -------------------------------------------------------------------------------- (Thousands) 1985 $ 50,000 9-3/8% 1985 81,500 9-1/4% =========== $ 131,500 ===========
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GEORGIA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Georgia Power Company 1995 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/ H. Allen Franklin
H. Allen Franklin President and Chief Executive Officer
/s/ Warren Y. Jobe Warren Y. Jobe Executive Vice President, Treasurer and Chief Financial Officer
February 21, 1996
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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 wholly owned subsidiary of The Southern Company) as of December 31, 1995 and 1994, 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, 1995. 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, 1995 and 1994, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1995 earnings totaled $609 million, representing an $83 million (15.9 percent) increase 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 the 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. Earnings for 1994 declined from the prior year not only because of the work force reduction charge but also because of lower retail energy sales due to mild weather. The summer of 1993 was exceptionally hot in comparison.
Revenues
The following table summarizes the factors impacting operating revenues for the 1993-1995 period:
Increase (Decrease) From Prior Year ----------------------------------- 1995 1994 1993 ----------------------------------- Retail - (in millions) Sales growth $110 $ 67 $ 45 Weather 69 (128) 126 Fuel cost recovery 66 (35) 76 Demand-side programs 36 (12) 15 ----------------------------------------------------------------- Total retail 281 (108) 262 - - ------------------------------------------------------------------ Sales for resale - Non-affiliates (61) (183) (106) Affiliates 16 (1) (6) - - ------------------------------------------------------------------ Total sales for resale (45) (184) (112) - - ------------------------------------------------------------------ Other operating revenues 7 3 4 - - ------------------------------------------------------------------ Total operating revenues $243 ($289) $154 - - ------------------------------------------------------------------ Percent change 5.8% (6.5)% 3.6% - - ------------------------------------------------------------------
Retail revenues of $4.0 billion in 1995 increased $281 million (7.6 percent) over the prior year, compared with a decrease of $108 million (2.8 percent) in 1994. Sales growth, reflecting continued expansion of Georgia's economy, and the hot summer of 1995, compared to the milder-than-normal weather during the summer of 1994, were the primary reasons for the increase in retail revenues. Retail revenues were down in 1994 from the prior year primarily due to hot summer weather in 1993.
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 1995 and 1994. 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:
1995 1994 1993 ------------------------------- (in millions) Capacity $53 $ 84 $152 Energy 45 82 113 - - -------------------------------------------------------------- Total $98 $166 $265 ==============================================================
Contractual unit power sales to Florida utilities for 1995 and 1994 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 155 megawatts and 427 megawatts in 1995 and 1994, respectively. In 1996, the contracted capacity will decline another 75 megawatts.
Sales to municipalities and cooperatives in Georgia increased in 1995 due to higher summer demand resulting from the hot weather; however, such sales decreased in 1994 as these customers retained more of their own generation at jointly owned facilities, and as a result of a new agreement with territorial wholesale customers.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1995 Annual Report
Kilowatt-hour (KWH) sales for 1995 and the percent change by year were as follows:
Percent Change ---------------------------- KWH 1995 1994 1993 ---------------------------------------- (in billions) Residential 17.3 10.4% (5.8)% 11.5% Commercial 19.8 5.9 2.5 5.9 Industrial 25.3 3.9 3.0 2.9 Other 0.5 2.0 5.0 5.7 ------- Total retail 62.9 6.2 0.4 6.1 ------- Sales for resale - Non-affiliates 6.6 (17.3) (44.3) (9.8) Affiliates 2.8 (10.4) 0.9 (8.8) ------- Total sales for resale 9.4 (15.4) (36.4) (9.7) ------- Total sales 72.3 2.8 (8.0) 2.1 ======= - - -----------------------------------------------------------------
Residential, commercial and industrial energy sales growth in 1995 reflected continued expansion of Georgia's economy, hot summer weather, and an increase in customers served. The 1994 sales decline in the residential class was primarily the result of milder-than-normal summer weather in 1994. However in 1994, industrial and commercial sales were positively impacted by continued improvement in economic conditions. Assuming normal weather, sales to retail customers are projected to grow approximately 2 percent annually on average during 1996 through 1998.
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:
1995 1994 1993 --------------------------- Total generation (billions of kilowatt-hours) 64 62 64 Sources of generation (percent) -- Coal 73.7 74.8 76.9 Nuclear 22.6 21.9 20.0 Hydro 3.0 3.1 2.8 Oil and gas 0.7 0.2 0.3 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.67 1.67 1.75 Nuclear 0.60 0.63 0.58 Oil and gas * * * Total 1.44 1.44 1.52 - - ---------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.
Fuel expense increased 3.5 percent in 1995 because of higher generation which stemmed from greater demand. Fuel expense decreased 8.5 percent in 1994 due to lower fuel costs, lower generation, and the displacement of coal-fired generation with lower cost nuclear generation.
Purchased power expense has decreased significantly since 1993, reflecting declining contractual capacity purchases from the co-owners of Plant Vogtle. Purchased power expense decreased $36 million in 1995 and $156 million in 1994. The declines in 1995 and 1994 also resulted from decreased purchases from affiliated companies, and in 1994 from decreased energy purchases from territorial wholesale customers. The declines in Plant Vogtle contractual capacity purchases did not have a significant impact on earnings in 1995 and 1994 since these costs are being levelized over six years under the terms of the 1991 Georgia Public Service Commission
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1995 Annual Report
(GPSC) retail rate order. The levelization is reflected in the amortization of deferred Plant Vogtle costs in the Statements of Income. See Note 3 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 $11 million in 1995 and $82 million in 1994.
Other operation and maintenance (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. Other O&M expenses decreased 4.5 percent in 1994 primarily due to environmental remediation costs at various sites of $32 million in 1993 compared to $8 million in 1994; recognition in 1993 of the one-time cost of an automotive fleet reduction program; and lower maintenance and pension costs during 1994.
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 5.2 percent in 1995 and 1.0 percent in 1994, reflecting primarily higher ad valorem taxes and in 1995, higher franchise taxes paid to municipalities as a result of increased sales.
Income tax expense fluctuates directly with earnings.
Other income (expense), net decreased in 1995 primarily due to an increase in charitable contributions.
Interest expense decreased $51 million (14.6 percent) and $61 million (14.7 percent) in 1995 and 1994, respectively, due primarily to refinancing of long-term debt. The Company refinanced $505 million and $510 million of securities in 1995 and 1994, respectively. The Company also retired $264 million of long-term debt with the proceeds from the 1995 and 1994 Plant Scherer Unit 4 sales. Other interest charges in 1993 include interest related to the settlement of an Internal Revenue Service (IRS) audit. The settlement had no effect on 1993 net income.
The Company has deferred certain expenses and recorded a deferred return related to Plant Vogtle under phase-in plans. See Note 3 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 either this economic loss or 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 energy sales and regulatory matters.
Beginning January 1, 1996, the Company will operate under a three-year retail rate plan. The plan, which was approved by the GPSC on February 16, 1996, concludes a GPSC review of the Company's earnings and addresses an alternative rate plan proposed by the Company. Under the plan, the Company's earnings will be 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1995 Annual Report
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 plan's three-year operation, including $14 million annually of accelerated depreciation of electric plant. During the plan'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 plan, 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 rate plan or adopt a different one.
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; 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 1996 through 1998.
The addition of four combustion turbine generating units and the Rocky Mountain pumped storage hydroelectric plant in 1995 and the scheduled addition of one jointly owned combustion turbine unit in 1996, will increase related O&M and depreciation expenses. In addition, the Company has entered into a four-year purchase power agreement to meet peaking needs whereby the Company will purchase 400 megawatts of capacity beginning in 1996 and declining to 200 megawatts of capacity in 1998. Capacity payments are projected to be $6 million in 1996 and 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.
Work force reduction programs implemented in 1994 and 1995 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 is approximately $190 million.
See Note 3 to the financial statements for information regarding proceedings with respect to the Company's recovery of demand-side conservation program costs.
During 1995, the Company sold its remaining interest in Unit 4 of Plant Scherer to two Florida utilities. This transaction coincided with scheduled reductions in capacity revenues from Florida utilities under contractual unit power sales contracts of approximately $22 million in 1995 and an additional $7 million in 1996. See Notes 6 and 7 to the financial statements for additional information.
During 1994 and 1995, Oglethorpe Power Corporation (OPC) gave the Company notice of its intent to decrease its purchases of capacity under a power supply agreement by 250 megawatts in September 1996 and an additional 250 megawatts in September 1997. As a result, the Company's capacity revenues from OPC will decline approximately $8 million in 1996, an additional $25 million in 1997, and an additional $18 million in 1998.
OPC and the Municipal Electric Authority of Georgia (MEAG) have filed joint complaints in two separate venues seeking to recover from the Company approximately $16.5 million in alleged overcharges, plus approximately $6.3 million in interest. See Note 3 to the financial statements under "Wholesale Litigation" for further discussion of this matter.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1995 Annual Report
Act and other environmental issues are discussed later under "Environmental Issues."
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 posturing 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. Although the Energy Act does not require transmission access to retail customers, retail wheeling initiatives are rapidly evolving and becoming very prominent issues in several states. New federal legislation is being discussed and legislation allowing customer choice has been introduced in Georgia. In order to address these initiatives, numerous questions must be resolved with the most complex ones relating to transmission pricing and recovery of stranded investments. As the initiatives become a reality, the structure of the utility industry could radically change. Therefore, 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. Conversely, being the low-cost producer could provide significant opportunities to increase market share and profitability.
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. In addition, the bulk power market has become very competitive as utilities, IPPs and cogenerators seek to supply future capacity needs. Competition can create new business opportunities, but it increases risk and has the potential to adversely affect 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 -- 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 increase. 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.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This statement also imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. The Company adopted this standard January 1, 1996 with no material effect on the financial statements. However, this conclusion may change in the future as competitive factors influence wholesale and retail pricing in this industry.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition in 1995 were gross utility plant additions of $480 million, which included the commercial operation of four combustion turbine units (cumulatively, 320 megawatts of capacity) and all three units of the Rocky Mountain pumped storage hydroelectric plant (the Company's ownership interest is approximately 70 megawatts of capacity per unit). In addition, the cost of capital was lowered through the refinancing or retirement of $1.0 billion of long-term debt.
The funds needed for gross property additions are currently provided from operations. The Statements of Cash Flows provide additional details.
Financing Activities
In 1995, the Company continued to lower its financing costs by refinancing higher-cost issues. New issues during 1993 through 1995 totaled $2.7 billion and retirement or repayment of securities totaled $3.4 billion. The retirements included the redemption of $131 million, $133 million, and $253 million in 1995, 1994, and 1993, respectively, of first mortgage bonds with the proceeds from the Plant Scherer Unit 4 sales. Composite financing rates for long-term debt and preferred stock for the years 1993 through 1995, as of year-end, were as follows:
1995 1994 1993 --------------------------------- Composite interest rate on long-term debt 6.57% 7.14% 7.86% Composite preferred stock dividend rate 6.73 7.11 6.76 - - ----------------------------------------------------------------
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 - - -----------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations increased by $281 million in 1995, primarily due to increased revenues and a decrease in interest payments.
The Company estimates that construction expenditures for the years 1996 through 1998 will total $530 million, $537 million and $529 million, respectively. Investments in transmission and distribution facilities, enhancements to existing generating plants, and additions of a combustion turbine generating plant and equipment to comply with the provisions of the Clean Air Act are planned.
Cash requirements for sinking fund requirements, redemptions announced, and maturities of long-term debt are expected to total $283 million during 1996 through 1998.
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 1996 through 1998, 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."
As a result of the Energy Policy Act of 1992, the Company is required to pay a special assessment over a 15-year period beginning in 1993 into a fund which will be used by the U. S. Department of Energy for the decontamination and decommissioning of its nuclear enrichment facilities. The Company estimates its remaining liability to be approximately $31 million as of December 31, 1995. See Note 1 to the financial statements under "Revenues and Fuel Costs" for additional information.
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 $975 million of unused credit
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1995 Annual Report
arrangements with banks at the beginning of 1996. 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 amended by Congress. 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 The 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 The 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.
In 1995, the Environmental Protection Agency (EPA) began issuing annual sulfur dioxide emission allowances through the newly established allowance trading program. An emission allowance is the authority to emit one ton of sulfur dioxide during a calendar year. The method for issuing allowances is based on the fossil fuel consumed from 1985 through 1987 for each affected generating unit. Emission allowances are transferable and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. The Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
The 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. Compliance with nitrogen oxide emission limits was achieved by the installation of new control equipment at 22 of the original 28 affected generating units. Construction expenditures for Georgia Power's Phase I compliance totaled approximately $165 million through 1995.
For Phase II sulfur dioxide compliance, The Southern Company could use emission allowances banked during Phase I, increase fuel switching, install flue gas desulfurization equipment at selected plants, and/or purchase more allowances depending on the price and availability of allowances. Also, in Phase II, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as required to meet anticipated Phase II limits. During the period 1996 to 2000, current compliance strategy could require total estimated Georgia Power construction expenditures of approximately $45 million. 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.
Metropolitan Atlanta is classified as a non-attainment area with regard to the ozone ambient air quality standards. Title I of the Clean Air Act requires the state of Georgia to conduct specific studies and establish new control rules - - -- affecting sources of nitrogen oxides and volatile organic compounds -- to achieve attainment by 1999. As the required first step, the state issued rules for the application of reasonably available control technology to reduce nitrogen oxide emissions by May 31, 1995. The results of these new rules require
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1995 Annual Report
nitrogen oxide controls, above Title IV requirements, on some of the Company's plants. The EPA along with 37 states is conducting studies to evaluate the benefits of regional controls in meeting the ozone standards. Final attainment rules, based on modeling studies, could require installation of additional controls for nitrogen oxide emissions to meet the 1999 deadline or as part of any regional controls if enacted. A decision on new requirements is expected in 1997. Compliance with any new rules could result in significant additional costs. The actual impact of new rules will depend on the development and implementation of such rules.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The EPA is scheduled to submit a report to Congress on the results of this study during 1996. The report will include a decision on whether additional regulatory control of these substances is warranted. Compliance with any new control standards could result in significant additional costs. The impact of new standards -- if any -- will depend on the development and implementation of applicable regulations.
The EPA is evaluating the need to revise the ambient air quality standards for particulate matter and ozone. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In 1996, the EPA may issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
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 $8 million in 1995 and 1994, and $32 million in 1993. Additional sites may require environmental remediation for which the Company may be liable for a portion of or all required cleanup 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 these requirements cannot be determined at this time, pending the development and implementation of applicable regulations.
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 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Company is a wholly owned subsidiary of The 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 Electric International (Southern Electric), 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). SCS provides, at cost, specialized services to The 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 Electric 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 The Southern Company's nuclear power plants. Southern Development develops new business opportunities related to energy products and services.
The Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both The 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:
1995 1994 -------------------- (in millions) Deferred income taxes $ 872 $ 920 Deferred income tax credits (410) (433) Deferred Plant Vogtle costs 308 432 Premium on reacquired debt 174 165 Demand-side program costs 79 97 Corporate building lease 49 48 Postretirement benefits 53 41 Vacation pay 36 41 Inventory conversions (31) (39) Department of Energy assessments 33 36 Other, net 36 52 ============================================================== Total $1,199 $1,360 ==============================================================
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 1995 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 1995, 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 $86 million in 1995, $87 million in 1994, and $75 million in 1993. 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 2009 at Plant Vogtle.
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, 1995, to be approximately $31 million. This obligation is recorded in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2 percent in 1995 and 3.1 percent in 1994 and 1993. See Note 3 under "Retail Rate Plan" for additional information. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -- together with the cost of removal, less salvage -- is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected costs of decommissioning nuclear facilities and removal of other facilities.
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations requiring all licensees operating commercial nuclear power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The Company has established external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over a set period of time as approved by the GPSC. Earnings on the trust funds are considered in determining decommissioning expense. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.
The 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 1995 Annual Report
date. The estimated costs of decommissioning -- both site study costs and ultimate costs at December 31, 1995 -- 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 1995 $11 $ 9
Accumulated provisions: Balance in external trust funds $56 $36 Balance in internal reserves 30 13 ============================================================ Total $86 $49 ============================================================
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 -- sinking fund -- 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 under plans that meet the requirements of FASB Statement No. 92, Accounting for Phase-In Plans. In 1991, the GPSC modified the phase-in plans. In addition, the Company deferred certain Plant Vogtle operating expenses and financing costs under accounting orders issued by the GPSC. See Note 3 for further information.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not 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 1995, 1994 and 1993, the average AFUDC rates were 6.53 percent, 6.18 percent and 4.96 percent, respectively. The increase in 1994 is primarily the result of the higher short-term borrowing rates. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 2.5 percent for 1995, 1994, and 1993.
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NOTES (continued) Georgia Power Company 1995 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; appropriate administrative and general costs; 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
In accordance with FASB Statement No. 107, Disclosure About Fair Value of Financial Instruments, the Company's financial instruments for which the carrying amounts did not approximate fair value at December 31 are as follows:
Carrying Fair Amount Value -------------------------- Long-term debt: (in millions) At December 31, 1995 $3,378 $3,487 At December 31, 1994 3,838 3,697 Preferred Securities: 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 1995 and 1994, the Company funded $21 million and $22 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. As a result of the regulatory treatment allowed by the GPSC, the adoption of Statement No. 106 did not have a material impact on net income.
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NOTES (continued) Georgia Power Company 1995 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 --------------------- 1995 1994 --------------------- Actuarial present value of (in millions) benefit obligations: Vested benefits $ 830 $ 689 Non-vested benefits 43 32 - - --------------------------------------------------------------- Accumulated benefit obligation 873 721 Additional amounts related to projected salary increases 290 294 - - --------------------------------------------------------------- Projected benefit obligation 1,163 1,015 Less: Fair value of plan assets 1,688 1,419 Unrecognized net gain (465) (371) Unrecognized prior service cost 26 28 Unrecognized transition asset (52) (58) =============================================================== Prepaid asset recognized in the Balance Sheets $ 34 $ 3 ===============================================================
Postretirement Benefits --------------------- 1995 1994 --------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $214 $203 Employees eligible to retire 16 7 Other employees 188 229 - - --------------------------------------------------------------- Accumulated benefit obligation 418 439 Less: Fair value of plan assets 81 52 Unrecognized net loss (gain) 44 (1) Unrecognized transition obligation 186 301 =============================================================== Accrued liability recognized in the Balance Sheets $107 $ 87 ===============================================================
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 postretirement benefits. This change reduced the 1995 accumulated postretirement benefit obligation by approximately $97 million.
The weighted average rates used in actuarial calculations were:
1995 1994 1993 ------------------------------- Discount 7.3% 8.0% 7.5% Annual salary increase 4.8 5.5 5.0 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 9.8 percent for 1995, decreasing gradually to 5.3 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, 1995, by $39 million and the aggregate of the service and interest cost components of the net postretirement cost by $8 million.
The components of the plans' net costs are shown below:
Pension ----------------------------- 1995 1994 1993 ----------------------------- (in millions) Benefits earned during the year $ 33 $ 34 $ 33 Interest cost on projected benefit obligation 78 71 69 Actual (return) loss on plan assets (317) 35 (194) Net amortization and deferral 185 (160) 84 ================================================================ Net pension cost $ (21) $ (20) $ (8) ================================================================
Net pension costs were negative in 1995, 1994 and 1993. Of net pension amounts recorded, $15 million in 1995 and 1994, and $6 million in 1993 were recorded as a
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NOTES (continued) Georgia Power Company 1995 Annual Report
reduction to operating expense, and the remainder was recorded as a reduction to construction and other accounts.
Postretirement Benefits -------------------------- 1995 1994 1993 -------------------------- (in millions) Benefits earned during the year $13 $15 $14 Interest cost on accumulated benefit obligation 34 33 29 Amortization of transition obligation 16 15 15 Actual (return) loss on plan assets (8) 1 (4) Net amortization and deferral 4 (3) 2 ================================================================== Net postretirement cost $59 $61 $56 ==================================================================
Of the above net postretirement benefit costs recorded, $33 million in 1995, $28 million in 1994, and $21 million in 1993 were charged to operating expenses. In addition, $11 million in 1995, $18 million in 1994, and $21 million in 1993 were deferred, and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The costs related to these programs were $11 million and $82 million for the years 1995 and 1994, respectively. Additionally, in 1994, the Company recognized $8 million for its share of costs associated with SCS's work force reduction program.
3. REGULATORY AND LITIGATION MATTERS
Retail Rate Plan
On February 16, 1996, the GPSC approved a rate plan recommended by the Commission staff which concludes the GPSC's review of the Company's earnings initiated in early 1995 and addresses the Company's proposed alternative retail rate plan. Under the three-year plan effective January 1, 1996, the Company's earnings will be 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 plan's three-year operation, including $14 million annually of accelerated depreciation of electric plant. During the plan'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 plan, 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 rate plan or adopt a different one.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky Mountain pumped storage hydroelectric plant in 1991, as then planned, was not economically justifiable and reasonable and withheld authorization for the Company to spend funds from approved securities issuances on that plant. In 1988, the Company and 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. However, full recovery of the Company's costs depends on the GPSC's treatment of the plant's costs and disposition of the plant's capacity output. 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. AFUDC accrued on the Rocky Mountain plant was not credited to income or included in the plant's cost since December 1985. In 1995, the plant went into commercial operation. At December 31, 1995, the Company's net investment in the plant was approximately $190 million, and the Company's ownership was 25.4 percent.
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.
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 judge held that the GPSC lacked statutory authority to approve such rate riders except through general rate case proceedings and that those procedures had not been followed. The Company suspended collection of the demand-side conservation
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costs and appealed the court's decision to the Georgia Court of Appeals. In December 1993, the GPSC approved the Company's request for an accounting order allowing the Company to defer all current unrecovered and future costs related to these programs until the Superior Court's decision is reversed or until the next general rate case proceedings.
After the Georgia Court of Appeals upheld the legality of the rate riders, the Company resumed collection under the rate riders in December 1994. 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.
Under the Retail Rate Plan 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. Any change in the rate of return on common equity that could potentially require refunds as a result of this proceeding would be substantially for the period beginning in July 1991 and ending in October 1992.
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. The second period under review for possible refunds began in October 1994 and ended in December 1995. 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 and refunds were ordered, the amount of refunds could range up to approximately $49 million at December 31, 1995. 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, 1995, the Company has recognized $3.5 million in expenses associated with this site. While the Company believes that the total amount of costs required for the clean up of this site may be substantial, it is unable at this time to estimate either such total or the portion for which the Company may ultimately be responsible.
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 these 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 24 sites which may require environmental remediation by the Company. The majority of these 24 sites are electrical power substations and power generation facilities. The Company has recognized $10 million in expenses through December 31, 1995 for the anticipated clean-up cost for 18 sites that the Company plans
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to remediate. The Company will conduct studies at each of the remaining sites to determine the extent of remediation and associated clean-up costs, if any, that may be required. The Company has recognized $2.4 million in expenses for the anticipated cost of completing such studies. Any cost of remediating the remaining sites cannot presently be determined until such studies are completed for each site and the State of Georgia determines whether remediation is required. If all listed sites were required to be remediated, the Company could incur expenses of up to approximately $15 million in additional clean-up costs and construction expenditures of up to approximately $100 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. The Company's response sought dismissal of the complaint by the FERC. Dismissal was ordered in November 1994. OPC and MEAG filed a request for rehearing in December 1994, and the FERC denied such request in July 1995. In September 1995, OPC appealed the FERC's decision on this issue to the Court of Appeals for the District of Columbia Circuit.
In August 1994, OPC and MEAG also filed a complaint in the Superior Court of Fulton County, Georgia, urging substantially the same claims and asking the court to hear the matter in the event the FERC declines jurisdiction. Such court proceeding was subsequently stayed pending resolution of the FERC filing.
Plant Vogtle Phase-In Plans
Pursuant to orders from the GPSC, the Company recorded a deferred return under phase-in plans for Plant Vogtle Units 1 and 2 until October 1991 when the allowed investment was fully reflected in rates. In addition, the GPSC issued two separate accounting orders that required the Company to defer substantially all operating and financing costs related to both units until rate orders addressed these costs. These GPSC orders provide for the recovery of deferred costs within 10 years. The GPSC modified the phase-in plans in 1991 to accelerate the recognition of costs previously deferred under the Plant Vogtle Unit 2 phase-in plan and to levelize the remaining Plant Vogtle declining capacity buyback expenses.
Under these orders, the Company has deferred and amortized these costs (as recovered through rates) as follows: 1995 1994 1993 ----------------------------- (in millions) Deferred costs at beginning of year $432 $507 $383 - - ---------------------------------------------------------------- Deferred capacity buyback expenses - 10 38 Amortization of previously deferred costs (124) (85) (74) - - ---------------------------------------------------------------- Net amortization (124) (75) (36) - - ---------------------------------------------------------------- Effect of adoption of FASB Statement No. 109 - - 160 ================================================================ Deferred costs at end of year $308 $432 $507 ================================================================
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 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. During this three-year period, the Company's units performed at an average capacity factor of 81 percent compared to an industry
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average of approximately 73 percent. Based on these results, the GPSC approved a performance reward of approximately $8.5 million for the Company. This reward is being collected through the retail fuel cost recovery provision and recognized in income over a 36-month period beginning November 1993. At December 31, 1995, the remaining amount to be collected was $2.4 million.
4. COMMITMENTS
Construction Program
While the Company has no new baseload generating plants under construction, the construction of one jointly owned combustion turbine peaking unit is planned to be completed in 1996. 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 $530 million in 1996, $537 million in 1997, and $529 million in 1998. These estimated additions include AFUDC of $12 million in 1996, $14 million in 1997, and $15 million in 1998. The estimates for property additions for the three-year period include $67 million committed to meeting the requirements of the Clean Air Act.
The construction program is subject to periodic review and revision, and actual construction costs may vary from estimates because of numerous factors, including, but not limited to, changes in business conditions, load growth estimates, environmental regulations, and regulatory requirements.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Total estimated long-term fossil and nuclear fuel commitments at December 31, 1995 were as follows:
Minimum Year Obligations ---------------------- (in millions) 1996 $ 831 1997 678 1998 534 1999 321 2000 231 2001 through 2010 1,624 =============================================================== Total minimum obligations $4,219 ===============================================================
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. These commitments are in effect during periods of up to 10 years following commercial operation (and with regard to a portion of a 5 percent interest in Plant Vogtle owned by MEAG, 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 $76 million, $129 million and $183 million in 1995, 1994, and 1993, respectively. The current projected Plant Vogtle capacity payments for the next five years are: $70 million in 1996, $59 million per year in 1997 through 1999, and $60 million in 2000. 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.
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As discussed in Note 3, 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:
1995 1994 1993 --------------------------------- (in millions) Energy $44 $43 $60 Capacity 29 33 30 ============================================================== Total $73 $76 $90 ============================================================== Kilowatt-hours 2,391 2,429 3,352 - - --------------------------------------------------------------
At December 31, 1995, the capitalization of SEGCO consisted of $54 million of equity and $78 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. Payments are subject to reductions for failure to meet minimum capacity output. Total estimated capacity and fixed operation and maintenance (O&M) payments are as follows:
Fixed Year Capacity O&M Total ----------------------------------------- (in millions) 1998 $ 10 $ 3 $ 13 1999 11 4 15 2000 11 4 15 2001 and beyond 178 157 335 ================================================================ Total $210 $168 $378 ================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $12 million, $13 million, and $8 million for 1995, 1994, and 1993, respectively. At December 31, 1995, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts ------------------- (in millions) 1996 $ 11 1997 10 1998 10 1999 10 2000 10 2001 and beyond 126 ========================================================= Total minimum payments $177 =========================================================
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident
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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 $12 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 $24 million for excess property damage and $13 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.
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.
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The Scherer Unit 4 transactions were as follows:
Closing Date Percent After-Tax 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.
In 1994, the Company and Florida Power Corporation (FPC) entered into a joint ownership agreement regarding a 150 megawatt combustion turbine unit to be constructed at Intercession City, Florida, near Orlando. The unit is scheduled to begin commercial operation by the end of 1996, and will be constructed, operated, and maintained by FPC. The Company will have a one-third interest in the unit, with use of 100 percent of the unit's capacity from June through September. FPC will have the capacity the remainder of the year. The Company's investment in the project is expected to be approximately $14 million at completion.
At December 31, 1995, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation, were as follows:
Total Nameplate Company Facility (Type) Capacity Ownership - - ----------------------------------------------------------------- (megawatts) Plant Vogtle (nuclear) 2,320 45.7% Plant Hatch (nuclear) 1,630 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) $3,295* $730 Plant Hatch (nuclear) 842 394 Plant Wansley (coal) 297 132 Plant Scherer (coal) Units 1 and 2 112 39 Unit 3 541 135 Plant McIntosh Common Facilities (combustion-turbine) 19 ** Rocky Mountain (pumped storage) 200 10 - - ----------------------------------------------------------------
* Investment net of write-offs. ** Less than $1 million.
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7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of The 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 have been as follows:
Year Unit Power Sales Non-firm Sales - - ----------------------------------------------------------------- (in millions) (megawatts) (in millions) (megawatts) 1995 $ 53 248 $ - - 1994 75 403 9 101 1993 135 830 17 200 - - -----------------------------------------------------------------
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 248 megawatts of capacity in 1995 and is scheduled to sell approximately 173 megawatts of capacity in 1996. Thereafter, these sales will decline to an estimated 159 megawatts and remain at that level through 1999. 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
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption resulted in the recording of additional deferred income taxes and related regulatory assets and liabilities. At December 31, 1995, the tax-related regulatory assets were $872 million and the tax-related regulatory liabilities were $410 million. The assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. The liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993 ------------------------------ Total provision for income taxes: (in millions) Federal: Currently payable $349 $306 $223 Deferred - Current year 84 86 181 Reversal of prior years (55) (57) (40) Deferred investment tax credits 1 (1) (18) - - ----------------------------------------------------------------- 379 334 346 - - ----------------------------------------------------------------- State: Currently payable 60 52 41 Deferred - Current year 15 15 31 Reversal of prior years (8) (10) (3) - - ----------------------------------------------------------------- 67 57 69 - - ----------------------------------------------------------------- Total 446 391 415 - - ------------------------------------------------------------------ Less: Income taxes charged (credited) to other income (3) (8) (37) ================================================================= Federal and state income taxes charged to operations $449 $399 $452 =================================================================
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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:
1995 1994 -------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,630 $1,541 Property basis differences 1,074 1,085 Deferred Plant Vogtle costs 100 141 Premium on reacquired debt 70 68 Deferred regulatory costs 38 48 Fuel clause underrecovered - 9 Other 29 23 - - ------------------------------------------------------------------ Total 2,941 2,915 - - ------------------------------------------------------------------ Deferred tax assets: Other property basis differences 239 250 Federal effect of state deferred taxes 97 94 Other deferred costs 83 79 Disallowed Plant Vogtle buybacks 25 26 Accrued interest 13 10 Fuel clause overrecovered 6 - Other 18 13 - - ------------------------------------------------------------------ Total 481 472 - - ------------------------------------------------------------------ Net deferred tax liabilities 2,460 2,443 Portion included in current assets 51 35 ================================================================== Accumulated deferred income taxes in the Balance Sheets $2,511 $2,478 ==================================================================
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $22 million in 1995, $25 million in 1994, and $19 million in 1993. At December 31, 1995, 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:
1995 1994 1993 ----------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 2 3 3 Difference in prior years' deferred and current tax rate (1) (1) (1) Other - - (1) ================================================================ Effective income tax rate 40% 41% 40% ================================================================
The 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
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, 1995, retained earnings of $897 million were 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.
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, 1995, the ratio as defined was 50.2 percent.
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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 mandatory redeemable preferred securities. The sole asset of Georgia Power Capital is $103 million aggregate principal amount of Georgia Power's 9 percent Junior Subordinated Deferrable Interest Debentures due December 19, 2024. 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 payment obligations with respect to the preferred securities.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public authorities of tax-exempt pollution control and industrial development 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 and industrial development 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 $146 million of the pollution control and industrial development bonds is secured by a subordinated interest in specific property of the Company.
Details of pollution control bonds are as follows:
Maturity Interest Rates 1995 1994 - - -------------------------------------------------------------- (in millions) 2000 4.375% $ 50 $ - 2004-2005 5% to 5.70% 143 85 2006-2008 6.375% to 6.75% 12 12 2011-2015 10.125% to 10.6% & Variable 10 515 2016-2019 6% to 9.375% 282 282 2021-2025 5.40% to 7.25% & Variable 1,181 784 ============================================================== Total pollution control bonds $ 1,678 $1,678 ==============================================================
Bank Credit Arrangements
At the beginning of 1996, the Company had unused credit arrangements with banks totaling $975 million, of which $514.7 million expires at various times during 1996, $60.3 million expires at May 1, 1998, and $400 million expires at June 30, 1998.
The $400 million expiring June 30, 1998, is under revolving credit arrangements with several banks providing the Company, Alabama Power Company, and The 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 The 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 1998, 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 $975 million in unused credit arrangements, a portion of the lines are dedicated to provide liquidity support to variable rate pollution control bonds. The credit lines dedicated as of December 31, 1995, were $475 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 1995.
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
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long-term debt. At December 31, 1995 and 1994, the Company had a capitalized lease obligation for its corporate headquarters building of $87 million and $88 million, respectively, with an interest rate of 8.1 percent. The maturity of this capital lease obligation through 2000 is approximately as follows: $336 thousand in 1996, $365 thousand in 1997, $395 thousand in 1998, $429 thousand in 1999, and $672 thousand in 2000.
The lease agreement for the corporate headquarters building 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, 1995, and 1994, the interest and lease amortization deferred on the Balance Sheets are $49 million and $48 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.
Long-Term Debt Due Within One Year
The current portion of the Company's long-term debt is as follows:
1995 1994 ----------------- (in millions) First mortgage bond maturity $150 $130 Other long-term debt - 37 ================================================================ Total $150 $167 ================================================================
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 Company currently plans to satisfy its 1996 improvement fund requirement by depositing cash with the trustee or by pledging additional property.
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 1995 and 1994 is as follows:
Net Income After Dividends on Operating Operating Preferred Quarter Ended Revenues Income Stock - - ------------------------------------------------------------------- (in millions) March 1995 $ 974 $207 $ 116 June 1995 1,075 230 149 September 1995 1,374 337 245 December 1995 982 177 99
March 1994 $ 992 $157 $ 58 June 1994 1,030 227 140 September 1994 1,213 331 233 December 1994 927 179 95 - - -------------------------------------------------------------------
Earnings in 1994 declined by $55 million as a result of work force reduction programs recorded primarily in the first quarter.
The Company's business is influenced by seasonal weather conditions.
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II-131A
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GEORGIA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1995
First Mortgage Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1993 $ 150,000 4-3/4% $ 150,000 3/1/96 1993 100,000 5-1/2% 100,000 4/1/98 1992 195,000 6-1/8% 195,000 9/1/99 1993 100,000 6% 100,000 3/1/00 1992 100,000 7% 100,000 10/1/00 1992 150,000 6-7/8% 150,000 9/1/02 1993 200,000 6-5/8% 200,000 4/1/03 1993 75,000 6.35% 75,000 8/1/03 1993 50,000 6-7/8% 50,000 4/1/08 1992 100,000 8-5/8% 60,368 6/1/22 1993 160,000 7.95% 160,000 2/1/23 1993 100,000 7-5/8% 100,000 3/1/23 1993 75,000 7-3/4% 75,000 4/1/23 1993 125,000 7.55% 125,000 8/1/23 1995 75,000 7.70% 75,000 5/1/25 ============= ============== $ 1,755,000 $ 1,715,368 ============= ==============
Pollution Control Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1995 $ 50,000 4-3/8% $ 50,000 11/1/00 1992 38,800 5.70% 38,800 9/1/04 1993 46,790 5-3/8% 46,790 3/1/05 1995 57,000 5% 57,000 9/1/05 1976 40,800 6-3/4% 1,920 11/1/06 1977 24,100 6.40% 1,940 6/1/07 1978 21,600 6-3/8% 8,060 4/1/08 1991 10,450 Variable 10,450 7/1/11 1986 56,400 8% 56,400 10/1/16 1987 90,000 8-3/8% 90,000 7/1/17 1987 50,000 9-3/8% 50,000 12/1/17 1993 26,700 6% 26,700 3/1/18 1989 50,000 6.35% 50,000 5/1/19 1991 8,500 6.25% 8,500 7/1/19 1991 51,345 7.25% 51,345 7/1/21 1991 10,125 6.25% 10,125 7/1/21 1992 13,155 Variable 13,155 5/1/22 1992 75,000 6.20% 75,000 8/1/22 1992 35,000 6.20% 35,000 9/1/22 1993 11,935 5-3/4% 11,935 9/1/23 1993 60,000 5-3/4% 60,000 9/1/23 1994 28,065 5.40% 28,065 1/1/24 1994 175,000 Variable 175,000 7/1/24 1994 125,000 6.60% 125,000 7/1/24 1994 60,000 6-3/8% 60,000 8/1/24 1994 43,420 6-3/4% 43,420 10/1/24 1994 20,000 Variable 20,000 10/1/24 1994 20,000 Variable 20,000 10/1/24 1994 38,725 6-5/8% 38,725 10/1/24 1994 10,000 5.90% 10,000 12/1/24 1994 7,000 5.90% 7,000 12/1/24 1995 73,535 6.10% 73,535 4/1/25 1995 75,000 Variable 75,000 4/1/25 1995 45,000 Variable 45,000 7/1/25 1995 40,000 Variable 40,000 7/1/25 1995 71,580 6% 71,580 7/1/25 1995 35,585 Variable 35,585 9/1/25 1995 30,000 Variable 30,000 9/1/25 1995 27,000 Variable 27,000 9/1/25 ============= ============== $ 1,752,610 $ 1,678,030 ============= ==============
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GEORGIA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1995 (Continued)
Subsidiary Obligated Mandatorily Redeemable Preferred Securities(1) Preferred Securities Interest Amount Series Outstanding Rate Outstanding - - -------------------------------------------------------------------------------- (Thousands) 1994 4,000,000 9% $ 100,000
Preferred Stock Shares Dividend Amount Series Outstanding Rate Outstanding - - -------------------------------------------------------------------------------- (Thousands) (2) 14,090 $5.00 $ 1,409 1953 100,000 $4.92 10,000 1954 433,774 $4.60 43,378 1961 70,000 $4.96 7,000 1962 70,000 $4.60 7,000 1963 70,000 $4.60 7,000 1964 50,000 $4.60 5,000 1965 60,000 $4.72 6,000 1966 90,000 $5.64 9,000 1967 120,000 $6.48 12,000 1968 100,000 $6.60 10,000 1971 300,000 $7.72 30,000 1972 750,000 $7.80 75,000 1991 4,000,000 $2.125 100,000 1992 2,000,000 $1.90 50,000 1992 2,200,000 $1.9875 55,000 1992 2,400,000 $1.9375 60,000 1992 1,200,000 $1.925 30,000 1993 3,000,000 Adjustable 75,000 1993 4,000,000 Adjustable 100,000 ------------- ------------ 21,027,864 $ 692,787 ============= ============
(1) Issued by Georgia Power Capital, L.P., and guaranteed to the extent Georgia Power Capital has funds by GEORGIA. (2) Issued in exchange for $5.00 preferred outstanding at the time of company formation.
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GEORGIA POWER COMPANY
SECURITIES RETIRED DURING 1995
First Mortgage Bonds Principal Interest Series Amount Rate - - ------------------------------------------------------------------------------ (Thousands) 1989 $ 36,157 9.23% 1992 130,000 5-1/8% 1992 100,000 8-3/4% 1992 39,632 8-5/8% 1992 100,000 Variable 1992 100,000 Variable =========== $ 505,789 ===========
Pollution Control Bonds Principal Interest Series Amount Rate - - ------------------------------------------------------------------------------ (Thousands) 1976 $ 20 6-3/4% 1977 20 6.40% 1978 70 6-3/8% 1985 148,535 10-1/8% 1985 156,580 10-1/2% 1985 100,000 10.60% 1985 99,585 10-1/2% ----------- $ 504,810 ===========
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GULF POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Gulf Power Company 1995 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 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 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 21, 1996
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REPORT OF INDEPENDENT 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 The Southern Company) as of December 31, 1995 and 1994, 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, 1995. 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-152 through II-169) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1995 net income after dividends on preferred stock was $57.2 million, an increase of $2 million over the prior year. This improvement is primarily attributable to higher retail revenues due to exceptionally hot summer weather and lower interest charges on long-term debt. This improvement was partially offset by higher maintenance expenses and reduced capacity revenues from non-affiliated utilities under long-term contracts. Costs related to a work force reduction program implemented in the fourth quarter of 1995 decreased earnings by $4.3 million. These costs are expected to be recovered through future savings over approximately two years.
In 1994, earnings were $55.2 million, representing an increase of $0.9 million compared to the prior year. Earnings in 1994 were significantly affected by lower financing costs, an increase in customers, and milder than normal temperatures. Also, earnings decreased approximately $3.0 million, reflecting the first full year of lower industrial sales due to the Company's largest industrial customer, Monsanto, installing its own cogeneration facility in August, 1993.
The return on average common equity for 1995 was 13.27 percent, a slight increase from the 13.15 percent return earned in 1994.
Revenues
Operating revenues increased in 1995 and decreased in 1994 as a result of the following factors:
Increase (Decrease) From Prior Year ------------------------------------- 1995 1994 1993 ------------------------------------- (in thousands) Retail -- Change in base rates $ - $ - $ 1,571 Sales growth 3,647 7,126 7,671 Weather 9,749 (4,631) 4,049 Regulatory cost recovery and other 22,502 8,938 (3,079) - - ----------------------------------------------------------------- Total retail 35,898 11,433 10,212 - - ----------------------------------------------------------------- Sales for resale-- Non-affiliates (5,698) (6,098) 2,131 Affiliates 1,266 (5,813) (909) - - ----------------------------------------------------------------- Total sales for resale (4,432) (11,911) 1,222 Other operating revenues 8,798 (3,851) 806 - - ----------------------------------------------------------------- Total operating revenues $40,264 $(4,329) $12,240 ================================================================= Percent change 7.0% (0.7)% 2.1% - - -----------------------------------------------------------------
Retail revenues of $519 million in 1995 increased $35.9 million or 7.4 percent from last year, compared with an increase of 2.4 percent in 1994 and 2.2 percent in 1993. Residential and commercial revenues surged upward as a result of hotter-than-normal summer weather in 1995, compared with the extremely mild summer of 1994. The Company set an all-time peak demand for energy in 1995.
The increase in regulatory cost recovery and other retail revenue is primarily attributable to the recovery of increased fuel costs. 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1995 Annual Report
Sales for resale were $79 million in 1995, decreasing $4.4 million or 5.3 percent from 1994. 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:
1995 1994 1993 ---------------------------------------- (in thousands) Capacity $25,870 $30,926 $33,805 Energy 18,598 18,456 21,202 ============================================================ Total $44,468 $49,382 $55,007 ============================================================
Capacity revenues decreased in 1995 and 1994, reflecting the scheduled decline in capacity under long-term contracts.
Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales have little impact on earnings.
The increase in other operating revenues for 1995 is primarily due to increased amounts collected to recover newly-imposed county franchise fees. These collections are also included in taxes other than income taxes and have no impact on earnings. Other changes for 1995 and the change in 1994 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 1995 and percent changes in sales since 1993 are reported below.
KWH Percent Change ------------ --------------------------- 1995 1995 1994 1993 ------------ --------------------------- (millions) Residential 4,014 7.0% 1.1% 3.2% Commercial 2,708 6.3 4.8 2.7 Industrial 1,795 (2.8) (9.0) (6.9) Other 17 (0.1) - - ------------ Total retail 8,534 4.5 (0.3) 0.4 Sales for resale Non-affiliates 1,397 (1.6) (2.8) 2.0 Affiliates 759 (13.1) (15.2) (14.8) ------------ Total 10,690 2.2 (2.1) (1.1) ==================================================================
Retail sales increased in 1995 due to hot summer weather, a 0.9 percent increase in residential customers, and a 2.2 percent increase in 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 1994, retail sales decreased from the prior year primarily due to mild summer weather and a decline in sales in the industrial class, which reflected the loss of Monsanto and a lengthy shutdown of another major customer.
In 1995, energy sales for resale to non-affiliates decreased 1.6 percent and are predominantly related to unit power sales under long-term contracts to Florida utilities. Energy sales to affiliated companies vary from year to year as mentioned previously.
Expenses
Total operating expenses for 1995 increased $41.3 million or 8.5 percent from 1994. The increase is due to higher fuel and purchased power expenses, higher maintenance expenses, and higher taxes other than income taxes, offset by lower depreciation and amortization expenses. In 1994, total operating expenses decreased $4.0 million or 0.8 percent from 1993 primarily due to decreased fuel and purchased power expenses, offset by an increase in other operation expenses and taxes.
Fuel and purchased power expenses for 1995 increased $30.1 million or 15.5 percent from 1994. The change reflects the increase in generation due to the extreme weather conditions during the summer of 1995 and slightly higher fuel
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1995 Annual Report
costs. In 1994, fuel and purchased power expenses declined $13.4 million or 6.5 percent from 1993 reflecting the decrease in generation due to the mild weather and the lower cost of fuel.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1995 1994 1993 ----------------------------- Total generation (millions of kilowatt-hours) 9,828 9,559 9,558 Sources of generation (percent) Coal 99.5 99.8 99.4 Oil and gas .5 .2 .6 Average cost of fuel per net kilowatt-hour generated (cents) Coal 2.08 2.00 2.03 Oil and gas 3.56 6.93 4.50 Total 2.09 2.01 2.05 - - ------------------------------------------------------------------
In 1995, other operation expenses decreased $0.5 million or 0.4 percent from the 1994 level. The decrease is primarily attributable to a $9.4 million reduction in the amortization costs of coal buyouts and renegotiation of coal supply contracts. This was offset by a $7 million accrual for benefits to be provided by the Company under a 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," respectively. In 1994, other operation expenses increased $4.7 million due to additional costs related to the buyouts and renegotiation of coal supply contracts and the Company's pro rata share of affiliated companies' work force reduction costs.
Maintenance expense in 1995 increased $5.2 million or 11.2 percent from the prior year. This is attributable to higher power production maintenance related to non-recurring items and higher distribution maintenance. In 1994, maintenance expense remained relatively flat reflecting no major changes in the scheduling of maintenance of production facilities.
Depreciation and amortization expenses decreased $1.5 million or 2.7 percent from 1994. The change is attributable to property which was fully amortized by December 1994. Refer to Note 1 to the financial statements under "Depreciation and Amortization" for further discussion.
Federal and state income taxes increased $0.1 million or 0.3 percent in 1995 due to a slight increase in taxable income. Taxes other than income taxes increased $7.9 million or 18.9 percent due to an increase in county franchise fees as mentioned previously. In 1994, federal income taxes increased $1.2 million due to an increase in taxable income. Other taxes increased $1.5 million or 3.7 percent due to higher property taxes, gross receipt taxes, and franchise fee collections. Changes in gross receipt taxes and franchise fee collections, which are collected from customers, have no impact on earnings.
In 1995, interest expense decreased $2.5 million or 7.8 percent below the prior year. The decline is mainly attributable to lower interest on long-term debt reflecting a lower average principal balance outstanding. The decrease in interest on long-term debt was partially offset by an increase in interest on notes payable as a result of a higher average amount of short-term notes outstanding. Interest expense in 1994 decreased $3.8 million or 10.5 percent under the prior year. The decrease was a result of refinancing some of the Company's higher-cost securities.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1995 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.
A work force reduction program was implemented in the fourth quarter of 1995 that reduced earnings by $4.3 million. This action will assist in efforts to control growth in future operating expenses.
The Florida Public Service Commission (FPSC) approved the Company's request in December 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. The approved accrual increase is intended to restore the account balance to a reasonable level within five years. 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 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 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 may enhance the incentive for IPPs to build cogeneration plants for industrial and commercial customers and sell excess 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.
Currently, Florida law does not permit retail wheeling. Although the Energy Act does not require transmission access to retail customers, retail wheeling initiatives are rapidly evolving and becoming very prominent issues in several states. Potential new federal legislation is being discussed, and legislation allowing customer choice has already been introduced in Florida. In order to address these initiatives, numerous questions must be resolved, with the most complex ones relating to transmission pricing and recovery of stranded investments. As the initiatives become a reality, the structure of the utility industry could radically change. Therefore, 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. Conversely, being the low-cost producer could provide significant opportunities to increase market share and profitability by seeking new markets that evolve with the changing regulation.
The future effect of cogeneration and small-power production facilities cannot be fully determined at this time. One effect of cogeneration which the Company has experienced was the loss in 1993 of its largest industrial customer, Monsanto, which is discussed in "Earnings." The Company's strategy is to identify and pursue profitable cogeneration projects in Northwest Florida.
The FPSC has 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 some generating facilities further into the future.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1995 Annual Report
On September 27, 1995, the Company filed a petition with the FPSC which seeks approval for a new optional Commercial/Industrial Service (CIS) rider, which would be applicable to the rate schedules serving the Company's largest and most at-risk customers who are able to show they have viable alternatives for electric power supply. The CIS rider would provide the flexibility needed to enable the Company to offer its services in a more competitive manner to these customers. The FPSC approval process is expected to take approximately 8 months.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air Act) could reduce earnings if such costs are not fully recovered. The Clean Air Act is 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 (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.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount for an asset may not be recoverable. This statement also imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. The Company adopted the new rules January 1, 1996, with no material effect on the financial statements. However, this conclusion may change in the future as competitive factors influence wholesale and retail pricing in the utility industry.
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition during 1995 were gross property additions of $63.1 million and an increase of $27 million in notes payable. Funds for the property additions were provided by internal sources. The increase in short-term notes payable is primarily attributable to a $22 million note issued in relation to a payment made to a coal supplier for a new arrangement under an existing coal contract. See the Statements of Cash Flows and Note 5 to the financial statements under "Fuel Commitments" for further details.
Financing Activities
The Company continued to lower its financing costs by retiring issues in 1995. Retirements, including maturities during 1995, totaled $1.8 million of first mortgage bonds, $0.1 million of pollution control bonds, $13.3 million of bank notes and other long-term debt, and $1 million of preferred stock. (See the Statements of Cash Flows for further details.)
Composite financing rates for the years 1993 through 1995 as of year end were as follows:
1995 1994 1993 ------------------------------ Composite interest rate on long-term debt 6.5% 6.5% 7.1% Composite preferred stock dividend rate 6.4% 6.6% 6.5% - - ----------------------------------------------------------------
The composite interest rate on long-term debt remained constant at 6.5% from 1994 primarily due to no new issues or refinancings during 1995. The decrease in the composite interest rate from 1993 to 1994 reflects the Company's efforts to refinance higher-cost debt. The decrease in the composite preferred dividend rate in 1995 is primarily due to a decrease in dividends on the Company's adjustable rate preferred stock, reflecting lower interest rates.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1995 Annual Report
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $209 million for the three years beginning in 1996 ($71 million in 1996, $67 million in 1997, and $71 million in 1998). The estimates of property additions for the three-year period include $9 million committed to meeting the requirements of the Clean Air Act, the cost of which is expected to be recovered through the Environmental Cost Recovery Clause (ECRC), which is discussed in Note 3 to the financial statements under "Environmental Cost Recovery." Actual construction costs may vary from this estimate because of factors such as changes in business conditions; changes in environmental regulations; revised 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 Company will be fully recovered. The Company does not have any baseload generating plants under construction, and current energy demand forecasts do not indicate a need for any additional baseload 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 $109 million will be required by the end of 1998 in connection with maturities of long-term debt. Also, the Company plans to continue a program to retire higher-cost debt and preferred stock and replace these obligations 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 -- has significantly impacted 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 The Southern Company. As a result of The Southern Company's compliance strategy, an additional 22 generating units were brought into compliance with Phase I requirements. Phase II compliance is required by 2000, and all fossil-fired generating plants will be affected.
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 legislation discussed below is expected to be recovered through the ECRC.
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 method for issuing allowances is based on the fossil fuel consumed from 1985 through 1987 for each affected generating unit. Emission allowances are transferable and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. The Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
The 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. Compliance with nitrogen oxide emission limits was achieved by the installation of new control equipment at 22 generating units. Construction expenditures for Phase I compliance totaled approximately $320 million for The Southern Company, including approximately $50 million for the Company through 1995.
For Phase II sulfur dioxide compliance, The Southern Company could use emission allowances banked during Phase I, increase fuel switching, install flue gas desulfurization equipment at selected plants, and/or purchase more allowances depending on the price and availability of allowances. Also, in Phase II, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired units as required to meet Phase II limits. Therefore, during the period 1996 to 2000, the current compliance strategy could
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1995 Annual Report
require total construction expenditures of approximately $150 million for The Southern Company, including approximately $10 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.
Following adoption of legislation in April of 1992 allowing electric utilities in Florida to seek FPSC approval of their Clean Air Act Compliance Plans, the Company 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.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The EPA is scheduled to submit a report to Congress on the results of this study in 1996. The report will include a decision on whether additional regulatory control of these substances is warranted. Compliance with any new control standards could result in significant additional costs. The impact of new standards -- if any -- will depend on the development and implementation of applicable regulations.
The EPA is evaluating the need to revise the ambient air quality standards for particulate matter and ozone. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In 1996, the EPA may issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
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 cleanup costs and has recognized in the financial statements costs to clean up known sites. Additional sites may require environmental remediation for which the Company may be liable for a portion or all required cleanup costs. 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 these requirements cannot be determined at this time, pending the development and implementation of applicable regulations.
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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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1995 Annual Report
Sources of Capital
At December 31, 1995, the Company had $0.7 million of cash and cash equivalents and $25 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.
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 The Southern Company. 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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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Gulf Power Company is a wholly owned subsidiary of The Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Electric International (Southern Electric), 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. Gulf Power Company provides electric service to the Northwest Panhandle of Florida. 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 The 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 Electric 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 The Southern Company's nuclear power plants. Southern Development develops new business opportunities related to energy products and services.
The Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both The 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:
1995 1994 ------------------------ (in thousands) Current & deferred coal contract costs $ 46,535 $ 40,690 Deferred income taxes 29,093 30,433 Deferred loss on reacquired debt 17,015 18,494 Environmental remediation 5,789 7,800 Vacation pay 4,419 4,172 Regulatory clauses under recovery, net 632 1,042 Deferred income tax credits (67,481) (71,964) Deferred storm charges 7,502 - Accumulated provision for property damage - (11,522) Other, net (1,510) (2,691) - - ---------------------------------------------------------------- Total $ 41,994 $ 16,454 ================================================================
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 values.
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NOTES (continued) Gulf Power Company 1995 Annual Report
Revenues and Regulatory Cost Recovery Clauses
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 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.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1995, uncollectible accounts continued to average significantly less than 1 percent of revenues.
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 1995 and 3.8 percent in 1994 and 1993. 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. The decrease in 1995 is attributable to property which was fully amortized by December 1994.
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 The 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 1995, 1994, and the second half of 1993 and 8.03 percent for the first half of 1993. AFUDC amounts for 1995, 1994, and 1993 were $223 thousand, $1.1 million, and $966 thousand, respectively. The decrease in 1995 is primarily due to the completion of major construction projects at Plant Daniel at the end of 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.
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 1995 Annual Report
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Values of Financial Instruments, financial instruments of the Company, for which the carrying amounts do not approximate fair value, are shown in the table below as of December 31:
---------------------------- Carrying Fair Amount Value ---------------------------- (in thousands) Long-term debt $354,924 $365,305 - - -------------------------------------------------------------
---------------------------- Carrying Fair Amount Value ---------------------------- (in thousands) Long-term debt $369,832 $355,019 Preferred stock subject to mandatory redemption 1,000 1,030 - - -------------------------------------------------------------
The fair values for long-term debt and preferred stock subject to mandatory redemption 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 $1.7 million and $2.5 million at December 31, 1995 and 1994, 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 damage to its transmission and distribution property. At December 31, 1995, in accordance with the FPSC's order, the accumulated provision for property damage had a negative balance of $7.5 million as the result of charges for expenses relating to Hurricanes Erin and Opal. The negative balance was reclassified to deferred storm charges in the accompanying Balance Sheets. The FPSC approved the Company's request in December to increase the amount of its annual accrual to the accumulated provision for property damage account from $1.2 million to $3.5 million, effective October 1, 1995. The approved accrual increase is intended to restore the account balance to a reasonable level within five years. The FPSC also ordered the Company to file within six months a study addressing the appropriate accumulated provision account balance and annual accrual amount. At December 31, 1994, the accumulated provision for property damage amounted to $11.5 million. The expense of repairing damages from major storms and other uninsured property damages are 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 1995 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 ------------------------- 1995 1994 ------------------------- (in thousands) Actuarial present value of benefit obligation: Vested benefits $ 87,652 $ 73,552 Non-vested benefits 4,284 3,016 - - ------------------------------------------------------------------ Accumulated benefit obligation 91,936 76,568 Additional amounts related to projected salary increases 29,073 29,451 - - ------------------------------------------------------------------ Projected benefit obligation 121,009 106,019 Less: Fair value of plan assets 180,980 151,337 Unrecognized net gain (48,438) (36,599) Unrecognized prior service cost 2,578 2,802 Unrecognized transition asset (7,187) (8,034) - - ------------------------------------------------------------------ Prepaid asset recognized in the Balance Sheets $ 6,924 $ 3,487 ==================================================================
Postretirement Benefits
--------------------------- 1995 1994 --------------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $ 9,759 $10,800 Employees eligible to retire 4,921 4,043 Other employees 17,646 19,639 - - ---------------------------------------------------------------- Accumulated benefit obligation 32,326 34,482 Less: Fair value of plan assets 7,050 5,740 Unrecognized net loss (gain) 1,538 (458) Unrecognized transition obligation 7,437 15,520 - - ---------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $16,301 $13,680 ================================================================
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:
1995 1994 1993 ----------------------------- Discount 7.3% 8.0% 7.5% Annual salary increase 4.8% 5.5% 5.0% 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 9.8 percent for 1995, decreasing to 5.3 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, 1995, by $2.5 million and the aggregate of the service and interest cost components of the net retiree cost by $610 thousand.
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NOTES (continued) Gulf Power Company 1995 Annual Report
Components of the plans' net costs are shown below:
Pension ------------------------------------ 1995 1994 1993 ------------------------------------ (in thousands) Benefits earned during the year $ 3,867 $ 3,775 $ 3,710 Interest cost on projected benefit obligation 8,042 7,484 7,319 Actual (return) loss on plan assets (33,853) 3,721 (20,672) Net amortization and deferral 19,619 (17,054) 8,853 - - ------------------------------------------------------------------ Net pension cost (income) $ (2,325) $(2,074) $ (790) ==================================================================
Of the above net pension amounts, pension income of $1.8 million in 1995, $1.5 million in 1994, and $601 thousand in 1993 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits -------------------------------- 1995 1994 1993 -------------------------------- (in thousands) Benefits earned during the year $1,259 $1,362 $1,166 Interest cost on accumulated benefit obligation 2,520 2,535 2,339 Amortization of transition obligation 853 854 854 Actual (return) loss on plan (1,268) 129 (731) assets Net amortization and deferral 742 (591) 310 - - ------------------------------------------------------------------- Net postretirement cost $4,106 $4,289 $3,938 ===================================================================
Of the above net postretirement costs recorded, $3.1 million in 1995 and 1994 and $3.0 million in 1993 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 $7 million in December for the total cost related to the program. These costs are expected to be recovered through future savings over approximately two years. The Company has also incurred its pro rata share for the costs of affiliated companies' programs. The costs related to these programs were $1 million, $1.3 million, and $109 thousand for the years 1995, 1994, and 1993, respectively.
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. Any change in the rate of return on common equity that may require refunds as a result of this proceeding would be substantially for the period beginning in July 1991 and ending in October 1992. 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. The second period under review for possible refunds was substantially from October 1994 through December 1995. 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 and refunds were ordered, the amount of refunds could range up to approximately $120 million for The Southern Company, including approximately $8 million for the Company at December 31, 1995. However, management believes that rates are not excessive and that refunds are not justified.
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NOTES (continued) Gulf Power Company 1995 Annual Report
FPSC Review of Earnings
As a result of an investigation of Gulf's 1995 earnings by the FPSC, Gulf presented a 1995 earnings proposal, which required deferring any jurisdictional revenues contributing to annual earnings in excess of a 12.75% jurisdictional-adjusted return on equity. The proposal was approved by the FPSC in August 1995. Gulf was to petition the FPSC to determine the disposition of any deferred revenues by April 1996. Based on 1995 actual results, no revenues were deferred.
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.
On January 12, 1994, the FPSC approved the Company's initial petition under the ECRC for recovery of environmental costs that were projected to be incurred from July 1993 through September 1994. Since this initial period, recovery under the ECRC has been determined semi-annually and includes a true-up of the prior period and a projection of the ensuing six month period. During 1995 and 1994, the Company recorded ECRC revenues of $11.8 million and $7.2 million, respectively.
At December 31, 1995, the Company's liability for the estimated costs of environmental remediation projects for known sites was $5.8 million. These estimated costs are expected to be expended during the period 1996 to 1999. These projects have been approved by the FPSC for recovery through the ECRC discussed above. Therefore, the Company recorded $2.0 million in current assets and $3.8 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 $71 million in 1996, $67 million in 1997, and $71 million in 1998. 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, 1995, significant purchase commitments were outstanding in connection with the construction program. The Company does not have any new baseload 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 financed from the sale of additional first mortgage bonds, pollution control bonds, and preferred stock; bank notes; and capital contributions from The 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. 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.
Bank Credit Arrangements
At December 31, 1995, the Company had $20 million in revolving credit lines that expire May 31, 1998, $5 million in revolving credit lines subject to renewal June 1, 1997, and $21.5 million of lines of credit with banks subject to renewal June 1 of each year, of which $25 million remained unused. In connection with these credit lines, the Company has agreed to pay commitment fees and/or to
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NOTES (continued) Gulf Power Company 1995 Annual Report
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 fourteen major money center banks that total $250 million, of which $37 million was committed at December 31, 1995.
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, 1995, were as follows:
Year Fuel ------- --------------- (in millions) 1996 $ 125 1997 126 1998 95 1999 86 2000 80 2001 - 2007 557 ------------------------------------------------------- Total commitments $1,069 =======================================================
To take advantage of lower-cost coal supplies, agreements were reached in 1986 to terminate two long-term contracts for the supply of coal to Plant Daniel, which is jointly owned by the Company and Mississippi Power, an operating affiliate. The Company's portion of this payment was $60 million. This amount is being amortized to expense on a per ton basis over a nine-year period. The remaining unamortized amount was $1.5 million at December 31, 1995.
In 1988, the Company made an advance payment of $60 million to another 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 $23 million at December 31, 1995.
In 1993, the Company made a payment of $16.4 million to a coal supplier under an arrangement to suspend the purchase of coal under an existing contract for one year. This amount was amortized to expense on a per ton basis during 1993, 1994, and the first quarter of 1995.
In December 1995, the Company made a payment of $22 million to a 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 to be amortized to expense on a per ton basis during 1996, 1997, and the first quarter of 1998.
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 1995 and $1.2 million in 1994 and 1993. The Company's annual lease payments for 1996 through 2000 will be approximately $1.7 million and after 2000, lease payments total approximately $22.4 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.
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NOTES (continued) Gulf Power Company 1995 Annual Report
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, an operating affiliate, jointly own Plant Scherer Unit No. 3. Plant Scherer is a steam-electric generating plant located near Forsyth, Georgia. In accordance with an operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is included in the corresponding operating expense accounts in the Statements of Income.
At December 31, 1995, 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 $185,755(1) $222,515 Accumulated Depreciation $49,982 $97,033 Construction Work in Progress $288 $683
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) 1995 $25,870 $ - $25,870 1994 29,653 1,273 30,926 1993 31,162 2,643 33,805 - - ----------------------------------------------------------
Unit power from specific generating plants of The 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, 210 megawatts of net dependable capacity were sold by the Company during 1995, 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 $25.4 million in 1995, $29.3 million in 1994, and $39.5 million in 1993, or 4.1 percent, 5.1 percent, and 6.8 percent of operating revenues, respectively.
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8. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption resulted in the recording of additional deferred income taxes and related regulatory assets and liabilities. At December 31, 1995, the tax-related regulatory assets to be recovered from customers were $29.1 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, 1995, the tax-related regulatory liabilities to be refunded to customers were $67.5 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
At December 31, 1995, the Company's current federal and state income taxes accrued, including the current portion of deferred income taxes, were equal to a debit balance of $4.2 million as a result of the early settlement of taxes owed. This amount was reclassified to current assets to reflect the tax prepayment and will be used to satisfy taxes accrued during 1996.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993 ---------------------------------- (in thousands) Total provision for income taxes: Federal-- Currently payable $29,018 $34,941 $24,354 Deferred--current year 23,172 18,556 26,396 --reversal of prior years (23,116) (24,787) (22,102) - - ------------------------------------------------------------------ 29,074 28,710 28,648 - - ------------------------------------------------------------------ State-- Currently payable 4,778 5,907 3,950 Deferred--current year 3,313 2,549 3,838 --reversal of prior years (2,979) (3,304) (2,785) - - ------------------------------------------------------------------ 5,112 5,152 5,003 - - ------------------------------------------------------------------ Total 34,186 33,862 33,651 Less income taxes charged (credited) to other income 121 (95) 921 - - ------------------------------------------------------------------ Federal and state income taxes charged to operations $34,065 $33,957 $32,730 ==================================================================
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:
1995 1994 ----------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $146,926 $146,686 Property basis differences 19,976 18,468 Coal contract buyouts 3,838 6,896 Property insurance 3,039 - Other 10,573 11,846 - - ------------------------------------------------------------------- Total 184,352 183,896 - - ------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 10,212 9,732 Postretirement benefits 5,494 4,383 Property insurance - 5,200 Other 6,313 7,566 - - ------------------------------------------------------------------- Total 22,019 26,881 - - ------------------------------------------------------------------- Net deferred tax liabilities 162,333 157,015 Less current portion, net (12) 5,334 - - ------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $162,345 $151,681 ===================================================================
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 1995, 1994 and 1993. At December 31, 1995, 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:
1995 1994 1993 ----------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 4 4 3 Non-deductible book depreciation 1 1 1 Difference in prior years' deferred and current tax rate (3) (2) (2) Other (2) (2) (1) - - --------------------------------------------------------------- Effective income tax rate 35% 36% 36% ===============================================================
The Company and the other subsidiaries of The 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
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NOTES (continued) Gulf Power Company 1995 Annual Report
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 bonds and other long-term debt at December 31 are as follows:
1995 1994 -------------------------- (in thousands) Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: Collateralized 6% due 2006* $ 12,075 $ 12,200 8.25% due 2017 32,000 32,000 7.125% due 2021 21,200 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 Remarketable daily 20,000 20,000 - - --------------------------------------------------------------- $169,630 $169,755 - - --------------------------------------------------------------- Notes payable: 5.39% due 1995 - 4,500 5.72% due 1995 - 4,500 4.69% due 1996 25,000 25,000 6.44% due 1994-1998 12,074 16,388 - - --------------------------------------------------------------- 37,074 50,388 - - --------------------------------------------------------------- Total $206,704 $220,143 ===============================================================
* Sinking fund requirement applicable to the 6 percent pollution control bonds is $200 thousand for 1996 with increasing increments periodically thereafter through 2005, with the remaining balance due in 2006.
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.
The 5.39 percent and 5.72 percent notes payable were the Company's portion of notes payable issued in connection with the termination of Plant Daniel coal contracts (see Note 5 under "Fuel Commitments" for further information). The estimated annual maturities of the notes payable through 2000 are as follows: $29.6 million in 1996, $4.9 million in 1997, $2.6 million in 1998, and none in 1999 and 2000.
10. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirement and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
1995 1994 ---------------------- (in thousands) Bond improvement fund requirement $ 1,750 $ 1,750 Less: Portion to be satisfied by cash or certifying property additions - 1,750 - - --------------------------------------------------------------- Cash sinking fund requirement 1,750 - Current portion of notes payable 29,598 13,314 (Note 9) Pollution control bond maturity 200 125 (Note 9) - - --------------------------------------------------------------- Total $31,548 $13,439 ===============================================================
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.
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NOTES (continued) Gulf Power Company 1995 Annual Report
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, 1995, retained earnings of $101 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, 1995, the ratio was 48.7 percent.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1995 and 1994 are as follows:
Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock - - ------------------------------------------------------------------ (in thousands) 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
March 31, 1994 $138,088 $19,154 $10,117 June 30, 1994 146,769 19,957 8,886 Sept. 30, 1994 162,143 31,123 21,831 Dec. 31, 1994 131,813 21,979 14,395 - - ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.
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II-170
II-171A
II-171B
II-171C
II-172
II-173A
II-173B
II-173C
II-174
II-175A
II-175B
II-175C
II-176
II-177A
II-177B
II-177C
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II-179A
II-179B
II-179C
II-180
II-181A
II-181B
II-181C
GULF POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1995
First Mortgage Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1992 $ 25,000 5-7/8% $ 25,000 8/1/97 1993 15,000 5.55% 15,000 4/1/98 1993 30,000 5% 30,000 7/1/98 1993 30,000 6-1/8% 30,000 7/1/03 1978 25,000 9% 930 9/1/08 1991 50,000 8-3/4% 50,000 12/1/21 ------------ ------------ $ 175,000 $ 150,930 ============ ============
Pollution Control Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1976 $ 12,500 6% $ 12,075 10/1/06 1987 32,000 8-1/4% 32,000 6/1/17 1991 21,200 7-1/8% 21,200 4/1/21 1992 8,930 6-3/4% 8,930 3/1/22 1993 13,000 6.20% 13,000 4/1/23 1993 32,550 5.80% 32,550 6/1/23 1993 7,875 5.70% 7,875 11/1/23 1994 22,000 6.30% 22,000 9/1/24 1994 20,000 Variable 20,000 9/1/24 ============ =========== $ 170,055 $ 169,630 ============ ===========
Preferred Stock Shares Dividend Amount Series Outstanding Rate Outstanding - - -------------------------------------------------------------------- (Thousands) 1950 51,026 4.64% $ 5,102 1960 50,000 5.16% 5,000 1966 50,000 5.44% 5,000 1969 50,000 7.52% 5,000 1972 50,000 7.88% 5,000 1992 580,000 7% 14,500 1992 600,000 7.30% 15,000 1993 800,000 6.72% 20,000 1993 600,000 Adjustable 15,000 ============ =========== 2,831,026 $ 89,602 ============ ===========
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GULF POWER COMPANY
SECURITIES RETIRED DURING 1995
First Mortgage Bonds Principal Interest Series Amount Rate - - -------------------------------------------------------------------------------- (Thousands) 1978 $ 1,750 9%
Pollution Control Bonds Principal Interest Series Amount Rate - - -------------------------------------------------------------------------------- (Thousands) 1976 $ 125 6%
Preferred Stock Principal Dividend Series Amount Rate - - -------------------------------------------------------------------------------- (Thousands) 1980 $ 1,000 11.36%
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MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Mississippi Power Company 1995 Annual Report
The management of Mississippi Power Company has prepared--and is responsible for--the financial statements and related information included in this report. These statements were prepared in accordance with generally accepted accounting principles appropriate in the circumstances and necessarily include amounts that are based on best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that books and records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based upon a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting control maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an ongoing basis by the internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of four directors who are not employees, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Mississippi Power Company in conformity with generally accepted accounting principles.
/s/ Dwight H. Evans Dwight H. Evans President and Chief Executive Officer
/s/ Michael W. Southern Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer
February 21, 1996
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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 The Southern Company) as of December 31, 1995 and 1994, 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, 1995. 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-194 through II-209) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP Atlanta, Georgia February 21, 1996
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's net income after dividends on preferred stock for 1995 totaled $52.5 million, an increase of $3.4 million over the prior year. This improvement is attributable primarily to increased energy sales and a rate increase under the Environmental Compliance Overview Plan (ECO Plan) of $3.7 million annually which became effective in May 1995.
A comparison of 1994 to 1993 reflects an increase in 1994 earnings of $6.7 million. Earnings in 1994 increased due to higher energy sales and increases in retail and wholesale rates.
In July 1993, a retail rate increase of $6.4 million annually became effective under the Company's Performance Evaluation Plan (PEP). Effective April 1994, retail rates increased by $7.6 million annually under the ECO Plan. Also, effective in April 1994 was a $3.6 million wholesale rate increase.
Revenues
The following table summarizes the factors impacting operating revenues for the past three years:
Increase (Decrease) from Prior Year ----------------------------------- 1995 1994 1993 ----------------------------------- (in thousands) Retail -- Change in base rates (PEP and ECO Plan) $ 2,694 $9,314 $ 5,079 Sales growth 4,045 9,560 5,606 Weather 4,513 1,752 4,735 Fuel cost recovery and other 3,806 6,594 15,028 ------------------------------------------------------------- Total retail 15,058 27,220 30,448 ------------------------------------------------------------- Sales for resale -- Non-affiliates 3,698 4,611 3,298 Affiliates (1,847) (5,981) 5,464 ------------------------------------------------------------- Total sales for resale 1,851 (1,370) 8,762 Other operating revenues 482 (1,571) 1,226 ------------------------------------------------------------- Total operating revenues $17,391 $24,279 $40,436 ============================================================= Percent change 3.5% 5.1% 9.3% -------------------------------------------------------------
Retail revenues of $410 million in 1995 increased 3.8 percent over the prior year, compared with increases of 7.4 percent and 9.0 percent in 1994 and 1993, respectively. The increase in retail revenues for 1995 was a result of growth in energy sales of 6.7% and 6.2% to commercial and residential customers, respectively, due to above normal summer temperatures. Additionally in 1995, an increase in the number of customers and a retail rate increase from the ECO Plan had a positive effect on retail revenues. A comparison of retail revenues of 1994 to 1993 reflects an increase resulting from growth in energy sales and customers and retail and wholesale rate increases. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1995 Annual Report
fuel expenses are offset with corresponding changes in fuel revenues and have no effect on net income.
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 13.1 percent in 1995 and 7.8 percent in 1994 with the related revenues rising 16.7 percent and 14.0 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:
1995 1994 1993 ------------------------------------- (in thousands) Capacity $ 268 $ 1,965 $ 4,191 Energy 3,627 8,473 12,120 ========================================================== Total $3,895 $10,438 $16,311 ==========================================================
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 1995 and the percent change for the last three years:
Amount Percent Change (millions of ----------- ------------------------------ kilowatt-hours) 1995 1995 1994 1993 ---------- ------------------------------ Residential 2,041 6.2% (0.4)% 6.9% Commercial 2,242 6.7 8.6 6.8 Industrial 3,813 (0.9) 6.2 2.5 Other 39 1.1 (0.5) 0.3 ---------- Total retail 8,135 2.9 5.1 4.7 Sales for resale -- Non-affiliates 2,493 (2.4) 0.4 (5.3) Affiliates 244 39.7 (59.2) 52.2 ---------- Total 10,872 2.2% 1.3% 3.3% ================================================================
Total retail energy sales in 1995 increased, compared to the previous year, due to both weather influences and the continued improving economy within the Company's service area, related primarily to the casino industry. In 1994, the most notable factor that increased commercial energy sales above the 1993 level was the establishment of casinos within the Company's service area. While the Company expects the number of new casinos to slow appreciably, it anticipates continued growth in ancillary services such as lodging, food, transportation, etc. Also, energy demand is expected to grow as a result of a larger and more fully employed population.
In addition to the previously discussed long-term contracts, 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.
Expenses
Total operating expenses for 1995 increased from 1994 due to higher fuel expenses, increased other operation expenses and increased depreciation and amortization. Expenses in 1994 were higher than 1993 primarily because of higher taxes and an increase in maintenance expenses and depreciation and amortization.
Fuel costs constitute the single largest expense for Mississippi Power. These costs increased in 1995 due to a 13.0% increase in generation caused by higher demand for energy throughout the Southern electric system. Further, this
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1995 Annual Report
increased demand for energy resulted in higher purchased power costs from the non-affiliates and lower purchased power costs from the affiliates of the Southern electric system. Fuel expenses in 1994, compared to 1993, were lower due to decreased generation reflecting lower demand.
Purchased power consists primarily 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:
1995 1994 1993 ------------------------------ Total generation (millions of kilowatt-hours) 8,368 7,408 7,836 Sources of generation generation (percent) -- Coal 58 56 64 Gas 15 10 7 Oil * * * Purchased Power 27 34 29 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.58 1.67 1.66 Gas 2.32 2.56 2.99 Oil 6.21 4.15 2.85 Total average cost of energy supply 1.53 1.55 1.58 - - -------------------------------------------------------------- * Not meaningful because of minimal generation from the fuel source.
Other operation expenses increased in 1995 due to an increase in generation, emission allowance expenses of $2.6 million and an increase in costs associated with work force reduction programs. (See Note 2 to the financial statements for information on these work force reduction programs.) This increase in expenses was offset by a decrease in maintenance costs for 1995, when compared to 1994. In 1994, work force reduction programs contributed to the increase in other operation expenses above the recorded 1993 level.
Depreciation and amortization increased in 1995, compared to 1994, due to additional plant investments. In 1994, depreciation and amortization expenses rose above 1993 primarily due to the addition in May 1994 of a 75 megawatt combustion turbine unit.
In 1995, taxes other than income taxes rose above the amount recorded for 1994 due to higher municipal franchise taxes. Taxes other than income taxes increased in 1994, when compared to 1993, because of higher ad valorem taxes, which are property based, and municipal franchise taxes, which are revenue based.
The change in income taxes between 1995 and 1994 reflects the change in operating income. The increase in income taxes in 1994 when compared to 1993 mirrored the increase 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1995 Annual Report
efficiency, and aggressively controlling the construction budget. Operating revenues will be affected by any changes in rates under the PEP, the Company's performance based ratemaking plan, and the ECO Plan. PEP has proven to be a stabilizing force on electric rates, with only moderate changes in rates taking place.
The ECO Plan, provides for recovery of costs 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 Southern 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 may enhance the incentive of IPPs to build cogeneration plants for a utility's large industrial and commercial customers and sell excess generation to other utilities. Although the Energy Act does not require transmission access to retail customers, retail wheeling initiatives are rapidly evolving and becoming very prominent issues in several states. In order to address these initiatives, numerous questions must be resolved with the most complex ones relating to transmission pricing and recovery of stranded investments. As the initiatives become a reality, the structure of the utility industry could radically change. Therefore, unless Mississippi Power remains a low-cost producer and provides quality service, the Company's retail energy sales growth could be limited, and this could significantly erode earnings. Conversely, being the low-cost producer could provide significant opportunities to increase market share and profitability.
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.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount for an asset may not be recoverable. This statement also imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. The Company adopted the new rules January 1, 1996, with no material effect on the financial statements. However, this conclusion may change in the future as competitive factors influence wholesale and retail pricing in the utility industry.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The principal changes in Mississippi Power's financial condition during 1995 were gross property additions to utility plant of $68 million. Funding for gross property additions and other capital requirements came primarily from earnings and other operating cash flows and from the sale of first mortgage bonds and pollution control bonds. The Statements of Cash Flows provide additional details.
Financing Activity
Mississippi sold $30 million of first mortgage bonds and $10.6 million of pollution control bonds during 1995. Retirements, including maturities during 1995, primarily related to other long-term debt, totaled some $42 million of securities. (See the Statements of Cash Flows for further details.) Composite financing rates for the years 1993 through 1995 as of year-end were as follows:
1995 1994 1993 ----------------------------- Composite interest rate on long-term debt 6.63% 6.44% 6.57%
Composite preferred stock dividend rate 6.58% 6.58% 6.58% -----------------------------------------------------------
Capital Structure
At year-end 1995, the Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, was 50.8 percent, compared to 48.7 percent in 1994. The increase in equity ratio in 1995 is attributed to a decrease in long-term debt and additional retained earnings.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $182 million ($67 million in 1996, $62 million in 1997, and $53 million in 1998). The major emphasis within the construction program will be on upgrading existing facilities. Also included in the estimates for property additions for the three-year period is $5.3 million committed to meeting the requirements of Clean Air Act regulations. 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 $92.3 million will be required by the end of 1998 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.
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 The 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 The 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 method for issuing allowances is based on the fossil fuel consumed from 1985 through 1987 for each affected generating unit. Emission allowances are transferable and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. The Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as a compliance option.
The 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1995 Annual Report
allowances being banked for later use. Compliance with nitrogen oxide emission limits was achieved by installation of new control equipment at 22 of the original 28 affected generating units. Construction expenditures for Phase I compliance totaled approximately $320 million through 1995 for The Southern Company, of which Mississippi Power's portion was approximately $65 million.
For Phase II sulfur dioxide compliance, The Southern Company could use emission allowances banked during Phase I, increase fuel switching, install flue gas desulfurization equipment at selected plants, and/or purchase more allowances depending on the price and availability of allowances. Also, in Phase II, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as required to meet Phase II limits. Therefore, during the period 1996 to 2000, current compliance strategy for The Southern Company could require total estimated construction expenditures of approximately $150 million, of which Mississippi Power's portion is approximately $5 million. 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 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. However, the plan also provides for carryover of any amount over the 2 percent limit into the next year's revenue requirement. Mississippi Power's management believes that the ECO Plan provides for recovery of the Clean Air Act costs. Under the ECO Plan, the Company had annual retail rate increases of $2.6 million, $7.6 million and $3.7 million in the years 1993, 1994 and 1995, respectively. On January 29, 1996, the Company filed the ECO Plan with the MPSC requesting an annual retail rate decrease of $3.0 million.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The EPA is scheduled to submit a report to Congress on the results of this study during 1996. The report will include a decision on whether additional regulatory control of these substances is warranted. Compliance with any new control standard could result in significant additional costs. The impact of new standards -- if any -- will depend on the development and implementation of applicable regulations.
The EPA is evaluating the need to revise the ambient air quality standards for particulate matter and ozone. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In 1996, the EPA may issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur costs to clean up properties currently or previously owned. Upon identifying potential sites, the Company conducts studies, when possible, to determine the extent of any required cleanup costs. Should remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. A currently owned site where manufactured gas plant operations were located prior to the Company's ownership was investigated for potential remediation. The remedial investigation has been concluded and is pending approval by the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1995 Annual Report
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. 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.
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 these requirements cannot be determined at this time, pending the development and implementation of applicable regulations.
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.
Sources of Capital
At December 31, 1995, the Company had $70 million of committed credit in revolving credit agreements and also had $27 million of committed short-term credit lines. The Company had no short-term notes payable outstanding at year end 1995.
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 The 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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11-194
II-195
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II-197
II-198
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NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company is a wholly owned subsidiary of The Southern Company, which is the parent company of five operating companies, Southern Company Services (SCS), Southern Communications Services (Southern Communications), Southern Electric International (Southern Electric), 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 The 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 Electric 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 The Southern Company's nuclear power plants. Southern Development develops new business opportunities related to energy products and services.
The Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both The 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: (in thousands)
1995 1994 ------------------------- Deferred income taxes $23,384 $25,036 Vacation pay 4,715 4,588 Work force reduction costs 7,286 11,286 Deferred fuel charges 1,546 10,068 Premium on reacquired debt 8,509 9,571 Deferred environmental costs 1,713 - Property damage reserve (12,018) (10,905) Deferred income tax credits (43,266) (45,832) Other, net (2,658) (3,383) ================================================================ Total $(10,789) $ 429 ================================================================
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
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fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between actual allowable amounts and the amounts included in rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1995, 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 3.2 percent in 1995 and 1994, and 3.1 percent in 1993. 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 other 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 8.0 percent in 1995, 6.9 percent in 1994, and 6.8 percent in 1993. AFUDC (net of income taxes), as a percent of net income after dividends on preferred stock, was 1.2 percent in 1995, and 3.5 percent in 1994 and 1993.
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, 1995, the fair value of long-term debt was $355 million and the carrying amount was $346 million. At December 31, 1994, the fair value of long-term debt was $331 million and the carrying amount was $348 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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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 1995, $1.1 million in 1994 and $1.5 million in 1993. 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, 1995, the accumulated provision amounted to $12.0 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 ------------------------ 1995 1994 ------------------------ (in thousands) Actuarial present value of benefit obligation: Vested benefits $91,322 $80,603 Non-vested benefits 4,264 2,966 -------------------------------------------------------------- Accumulated benefit obligation 95,586 83,569 Additional amounts related to projected salary increases 28,545 27,292 -------------------------------------------------------------- Projected benefit obligation 124,131 110,861 Less: Fair value of plan assets 170,481 145,598 Unrecognized net gain (47,034) (37,485) Unrecognized prior service cost 2,868 3,109 Unrecognized transition asset (6,001) (6,635) -------------------------------------------------------------- Prepaid asset (accrued liability) recognized in the Balance Sheets $(3,817) $(6,274) ==============================================================
Postretirement Benefits ------------------------ 1995 1994 ------------------------ (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $22,575 $22,833 Employees eligible to retire 1,709 774 Other employees 17,908 22,851 ------------------------------------------------------------ Accumulated benefit obligation 42,192 46,458 Less: Fair value of plan assets 8,700 6,608 Unrecognized net loss (gain) 4,160 1,751 Unrecognized transition obligation 7,044 18,668 ------------------------------------------------------------ Accrued liability recognized in the Balance Sheets $22,288 $19,431 ============================================================
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In 1995, The Southern Company's subsidiaries announced a cost sharing program for postretirement benefits. The program establishes 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:
1995 1994 1993 --------------------------------- Discount 7.3% 8.0% 7.5% Annual salary increase 4.8 5.5 5.0 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 9.8 percent for 1995, decreasing gradually to 5.3 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, 1995, by $3.3 million and the aggregate of the service and interest cost components of the net retiree cost by $0.8 million.
Components of the plans' net cost are shown below:
Pension -------------------------------- 1995 1994 1993 -------------------------------- (in thousands) Benefits earned during the year $ 3,636 $ 3,780 $ 3,792 Interest cost on projected benefit obligation 8,434 7,503 7,296 Actual (return) loss on plan assets (32,232) 3,244 (20,017) Net amortization and deferral 18,650 (16,048) 8,741 ============================================================== Net pension income $ (1,512) $ (1,521) $ (188) ==============================================================
Of the above net pension income, $(1.1) million in both 1995 and 1994, and $(170) thousand in 1993 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits --------------------------------- 1995 1994 1993 --------------------------------- (in thousands) Benefits earned during the year $1,525 $1,760 $1,448 Interest cost on accumulated benefit obligation 3,442 3,251 2,811 Amortization of transition obligation over 20 years 1,027 1,043 1,051 Actual (return) loss on plan assets (1,436) 132 (814) Net amortization and deferral 851 (575) 343 ================================================================== Net postretirement costs $5,409 $5,611 $4,839 ==================================================================
Of the above net postretirement costs recorded, $3.9 million in 1995, $4.4 million in 1994, and $3.9 million in 1993 were charged to operating expense.
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 $4.0 million and $3.0 million of the cost of these programs in 1995 and 1994, respectively.
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 performance as measured by three indicators that emphasize price and service to the customer. PEP-2 provides for semiannual evaluations of Mississippi's
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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 increases under PEP-2.
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 (TFA) discussed in Note 5 under "Lease Agreements." Any change in the rate of return on common equity that may require refunds as a result of this proceeding would be substantially for the period beginning in July 1991 and ending in October 1992.
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. The second period under review for possible refunds was from October 1994 through December 1995. 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 and refunds were ordered, the amount of refunds could range up to approximately $2.0 million at December 31, 1995. 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 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 has resulted in annual retail rate increases, the latest being an increase of $3.7 million, effective in May 1995 which included $1.6 million of 1994 carryover. On January 29, 1996, the Company filed the ECO Plan with the MPSC requesting an annual retail rate decrease of $3.0 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 was investigated for potential remediation. The remedial investigation has been concluded and is pending approval by 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. If this site were required to be remediated, industry studies show the Company could incur cleanup costs ranging from $1.5 million to $10 million before giving consideration to possible recovery of clean-up costs from other parties.
4. CONSTRUCTION PROGRAM
Mississippi Power is engaged in continuous construction programs, the costs of which are currently estimated to total some $67 million in 1996, $62 million in 1997, and $53 million in 1998. These estimates include AFUDC of $1.3 million in
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1996, and $0.3 million in both 1997 and 1998.
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 have any new 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.
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 The 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, 1995, Mississippi Power had unused committed credit agreements with banks for $27 million. Additionally, Mississippi Power had $70 million of unused committed credit agreements in the form of revolving credit agreements expiring at various dates during 1996 and in 1998. The agreements expiring December 1, 1998, for $40 million 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. The Company had no short-term borrowings outstanding at year-end 1995.
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 1995 use fees collected under this agreement, net of related expenses, amounted to $3.8 million each year, and are included with other income, net, in the Statements of Income. For more information see Note 3 under "FERC Reviews Equity Returns."
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 1995 and $1.2 million in both 1994 and 1993. The Company's annual lease payments for 1996 through 2000 will be approximately $1.7 million and after 2000, lease payments total approximately $22.4 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 Commitments
To supply a portion of the fuel requirements of its generating plants, Mississippi Power has entered into various long-term commitments for the procurement of fuel. In most cases, these contracts contain provisions for price escalations, minimum production levels, and other financial commitments. Total estimated obligations were approximately $227 million at December 31, 1995.
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Additional commitments for fuel will be required in the future to supply the Company's fuel needs.
In order to take advantage of lower cost coal supplies, agreements were reached in 1986 to terminate two contracts for the supply of coal to Plant Daniel, which is jointly owned by Mississippi Power and Gulf Power, an operating affiliate. The Company's portion of this payment was about $60 million. In accordance with the ratemaking treatment, the cost to terminate the contracts is being amortized to match costs with the savings achieved. The remaining unamortized amount of Mississippi Power's share of payments to the suppliers totaled $1.5 million at December 31, 1995.
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, 1995, 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% $ 57,957 $ 31,201
Daniel 1,000 50% 222,367 94,172 ---------------------------------------------------------------
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 The 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. The agreements for non-firm capacity expired in 1994. 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. However, the Company continues to participate in transmission and energy sales under the unit power sales agreements. Because the energy is generally sold at variable costs under these agreements, only revenues from capacity sales affect profitability. Off-system capacity revenues for the Company have been as follows:
Other Year Unit Power Long-Term Total ------------------------------------------------------------ (in thousands) 1995 $ 268 $ - $ 268 1994 660 1,305 1,965 1993 1,571 2,620 4,191
In 1994, long-term non-firm power of 200 megawatts was sold by the Southern electric system to Florida Power Corporation (FPC) until the contract expired at year-end.
8. INCOME TAXES
Effective January 1, 1993, Mississippi Power adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption resulted in the recording of additional deferred income taxes and related regulatory assets and liabilities. At December 31, 1995, the tax-related regulatory assets to be recovered from customers were $23 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, 1995, the tax-related regulatory liabilities to be refunded to customers were $43 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and unamortized investment tax credits.
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Details of the federal and state income tax provisions are shown below:
1995 1994 1993 --------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $32,546 $26,072 $15,842 Deferred --current year 5,122 6,313 5,158 --reversal of prior years (7,039) (5,161) (820) --------------------------------------------------------------- 30,629 27,224 20,180 --------------------------------------------------------------- State -- Currently payable 3,426 3,978 2,945 Deferred --current 2,270 1,669 1,339 --reversal of prior years (833) (1,258) (638) -------------------------------------------------------------- 4,863 4,389 3,646 --------------------------------------------------------------- Total 35,492 31,613 23,826 Less income taxes charged to other income 1,006 227 1,158 --------------------------------------------------------------- Federal and state income taxes charged to operations $34,486 $31,386 $22,668 ===============================================================
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:
1995 1994 ----------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $145,093 $138,281 Basis differences 10,815 11,645 Coal contract buyouts 145 3,851 Other 16,478 17,908 ------------------------------------------------------------- Total 172,531 171,685 ------------------------------------------------------------- Deferred tax assets: Other property basis differences 25,951 27,375 Pension and other benefits 7,356 5,386 Property insurance 4,551 4,171 Unbilled fuel 3,039 3,649 Other 7,103 7,009 ------------------------------------------------------------- Total 48,000 47,590 ------------------------------------------------------------- Net deferred tax liabilities 124,531 124,095 Portion included in current assets, net 5,180 5,410 ------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $129,711 $129,505 =============================================================
In 1989, under order of the MPSC, Mississippi Power began amortizing deferred income taxes not covered by the Internal Revenue Service normalization requirements, that had been recorded at rates higher than those specified by the current statutory income tax rules. This amortization occurred over a 60-month period, the effect of which was a reduction of income tax expense of approximately $2.7 million per year. This tax rate differential has been fully amortized.
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 $1.5 million in 1995, 1994 and 1993. At December 31, 1995, all investment tax credits available to reduce federal income taxes payable had been utilized.
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A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
1995 1994 1993 ----------------------------- Total effective tax rate 38% 37% 33% State income tax, net of federal income tax benefit (3) (3)% (3) Tax rate differential - 1 4 Other - - 1 ------------------------------------------------------------- Statutory federal tax rate 35% 35% 35% =============================================================
Mississippi Power and the subsidiaries of The Southern Company file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Tax benefits from losses of the parent company are allocated to each subsidiary based on the ratio of taxable income to total consolidated taxable income.
9. OTHER LONG-TERM DEBT
Details of other long-term debt are as follows:
December 31, 1995 1994 --------------------- (in thousands) Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: 5.8$% due 2007 $ 970 $ 980 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 - ------------------------------------------------------------ 73,745 63,155 ------------------------------------------------------------ Notes payable: 4.15% to 7.50% due 1995 - 40,689 Variable rates (5.88% to 5.89% at 1/1/95) due 1995 - 20,000 Variable rates (5.85% to 6.015% at 1/1/96) due 1996 55,000 35,000 ------------------------------------------------------------ 55,000 95,689 ------------------------------------------------------------ Total $128,745 $158,844 ============================================================
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 5.8% Series of pollution control obligations has a cash sinking fund requirement of $10 thousand annually through 1997 and $20 thousand annually in 1998, 1999 and 2000. The $55 million in notes payable is all due in 1996.
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:
1995 1994 -------------------- (in thousands) Bond improvement fund requirements $ 2,219 $ 1,931
Less: Portion to be satisfied by certifying property additions - 1,431 ------------------------------------------------------------- Cash improvement fund requirements 2,219 500 Pollution control bond cash sinking fund requirements (Note 9) 10 10 Current portion of notes payable (Note 9) 55,000 40,689 ============================================================= Total $57,229 $41,199 =============================================================
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, 1995, some $118 million of retained earnings was restricted against the payment of cash dividends on common stock under the most restrictive terms of the mortgage indenture or corporate charter.
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12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1995 and 1994 are as follows:
Net Income After Dividends Quarter Operating Operating On Ended Revenues Income Preferred Stock -------------------------------------------------------------------
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
March 1994 $114,134 $12,910 $ 8,266 June 1994 131,792 19,891 13,744 September 1994 142,340 26,212 21,357 December 1994 110,896 14,062 5,790
Mississippi Power's business is influenced by seasonal weather conditions and the timing of rate changes.
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MISSISSIPPI POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1995
First Mortgage Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1993 $ 35,000 5-3/8% $ 35,000 3/1/98 1992 40,000 6-5/8% 40,000 8/1/00 1994 35,000 6.60% 35,000 3/1/04 1991 50,000 9-1/4% 45,447 5/1/21 1993 35,000 7.45% 35,000 6/1/23 1995 30,000 6-7/8% 30,000 12/1/25 =========== =========== $ 225,000 $ 220,447 =========== ===========
Pollution Control Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1977 $ 1,000 5.80% $ 970 10/1/07 1992 6,550 Variable 6,550 12/1/20 1992 16,750 Variable 16,750 12/1/22 1993 13,000 6.20% 13,000 4/1/23 1993 25,875 5.65% 25,875 11/1/23 1995 10,600 Variable 10,600 7/1/25 =========== =========== $ 73,775 $ 73,745 =========== ===========
Preferred Stock Shares Dividend Amount Series Outstanding Rate Outstanding - - ------------------------------------------------------------------- (Thousands) 1947 20,099 4.60% $ 2,010 1956 40,000 4.40% 4,000 1965 50,000 4.72% 5,000 1968 50,000 7.00% 5,000 1992 350,000 7.25% 35,000 1993 150,000 6.32% 15,000 1993 84,040 6.65% 8,404 ========= =========== 744,139 $ 74,414 ========= ===========
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MISSISSIPPI POWER COMPANY
SECURITIES RETIRED DURING 1995
First Mortgage Bonds Principal Interest Series Amount Rate - - -------------------------------------------------------------------------------- (Thousands) 1991 $ 1,625 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 1995 Annual Report
The management of Savannah Electric and Power Company has prepared--and is responsible for--the financial statements and related information included in this report. These statements were prepared in accordance with generally accepted accounting principles appropriate in the circumstances and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that books and records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of four directors who are not employees, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls and financial reporting matters. The internal auditors and the independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Savannah Electric and Power Company in conformity with generally accepted accounting principles.
/s/ 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 21, 1996
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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 The Southern Company) as of December 31, 1995 and 1994, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. 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-233 through II-245) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 1995 totaled $23.4 million, representing a $1.3 million increase over the prior year. This 5.8 percent improvement in earnings over 1994 is principally the result of increased retail energy sales, primarily attributable to exceptionally hot summer weather.
In 1994, earnings were $22.1 million, representing a $0.6 million (3.0 percent) increase from the prior year. This increase was primarily due to a decrease in operating expenses, offset somewhat by an increase in interest expense.
Revenues
Total revenues for 1995 were $225.7 million, reflecting a 6.6 percent increase compared to 1994. The following table summarizes revenue increases and decreases compared to prior years: Increase (Decrease) From Prior Years -------------------------------------- 1995 1994 1993 -------------------------------------- Retail -- (in thousands) Change in base rates $ - $ - $(1,450) Sales growth 1,068 7,884 5,980 Weather 6,232 (6,589) 4,567 Fuel cost recovery and other 6,177 (9,214) 12,404 ------------------------------------------------------------------- Total retail 13,477 (7,919) 21,501 ------------------------------------------------------------------- Sales for resale-- Non-affiliates (2,935) (1,235) (1,800) Affiliates 754 4,013 928 ------------------------------------------------------------------- Total sales for resale (2,181) 2,778 (872) ------------------------------------------------------------------- Other operating revenues 2,648 (1,516) 52 ------------------------------------------------------------------- Total operating revenues $13,944 $(6,657) $20,681 =================================================================== Percent change 6.6% (3.0)% 10.5% -------------------------------------------------------------------
Retail revenues increased 6.7 percent in 1995, compared to a decrease of 3.8 percent in 1994. The increase in 1995 retail revenues is 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. Industrial energy sales were higher primarily because a major customer performed maintenance on its cogeneration facility during 1995 and purchased replacement energy from the Company. Under the Company's fuel cost recovery provisions, fuel revenues--including purchased energy--generally equal fuel expense and have no effect on earnings. The $2.6 million increase in other operating revenues reflects a decrease in the demand-side management rider in October 1994 and an increase in demand-side management program costs during 1995. Revenues from demand-side management riders (included in retail revenues) recover demand-side management program costs and have little impact on earnings. See Note 3 to the financial statements for further information on the Company's demand-side management programs.
The decrease in 1994 retail revenues as compared to 1993 resulted from mild summer weather, reduced industrial energy sales, and substantially lower fuel cost recovery revenues, offset somewhat by customer growth.
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 and energy revenues continued to decrease in 1995 and 1994 primarily as a result of the scheduled decline in megawatts of capacity under contract. The capacity and energy components were as follows:
1995 1994 1993 ------------------------------------ (in thousands) Capacity $ 3 $ 448 $ 978 Energy 1,250 3,052 4,262 - - --------------------------------------------------------- Total $ 1,253 $3,500 $5,240 =========================================================
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 1995 Annual Report
Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1995 and the percent change by year were as follows:
Percent Change ------------------------------ KWH 1995 1994 1993 --------- ------------------------------ (in millions) Residential 1,402 8.0% (2.3)% 9.2% Commercial 1,100 5.1 2.9 6.5 Industrial 887 11.0 (6.4) (0.8) Other 126 5.4 3.1 5.2 --------- Total retail 3,515 7.7 (1.6) 5.5 Sales for resale - Non-affiliates 87 (56.5) (18.4) (32.7) Affiliates 64 (31.5) 23.4 100.3 --------- Total 3,666 3.1% (2.2)% 2.6% =========
=================================================================
Expenses
Total operating expenses for 1995 were $187.5 million, reflecting an $11.8 million increase over 1994. Major components of this increase include $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 is 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 is 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.
Total operating expenses for 1994 were $175.6 million, reflecting an $8.6 million decrease from 1993. This decrease includes a $5.8 million reduction in fuel and purchased power expenses, reflecting a decrease in total energy requirements. The $4.9 million reduction in 1994 in other operation and maintenance expenses reflects the $4.5 million work force reduction charge in 1993 and a $1.1 million reduction in power generation expenses in 1994. This was offset by an increase in depreciation expense because of additions to utility plant discussed above. Interest expense increased $1.9 million primarily due to the sale in June 1993 of $45 million of first mortgage bonds.
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:
1995 1994 1993 -------------------------- Total energy supply (millions of kilowatt-hours) 3,908 3,768 3,863 Sources of energy supply (percent) -- Coal 24 18 21 Oil - 1 2 Gas 6 1 3 Purchased Power 70 80 74 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.77 2.19 2.02 Oil 5.14 3.89 4.11 Gas 3.76 5.19 4.87 Average cost of purchased power per net kilowatt- hour (cents) 2.02 1.92 2.00 Total average cost of energy supply 2.07 2.02 2.12 ===============================================================
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1995 Annual Report
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 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 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 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 excess energy generation to other utilities.
Although the Energy Act does not require transmission access to retail customers, retail wheeling initiatives are rapidly evolving and becoming very prominent issues in several states. New federal legislation is being discussed, and legislation allowing customer choice has already been introduced in Georgia. In order to address these initiatives, numerous questions must be resolved, with the most complex ones relating to transmission pricing and recovery of stranded investments. As the initiatives become a reality, the structure of the utility industry could radically change. Therefore, 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. Conversely, being the low-cost producer could provide significant opportunities to increase market share and profitability by seeking new markets that evolve with the changing regulation.
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities 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. The Company will refund to customers approximately $0.2 million which had been overcollected from the rate riders as of December 31, 1995.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement requires that long-lived assets be reviewed for impairment whenever events or
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1995 Annual Report
changes in circumstances indicate that the carrying amount for an asset may not be recoverable. This statement also imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. The Company adopted the new rules January 1, 1996, with no material effect on the financial statements. However, this conclusion may change in the future as competitive factors influence wholesale and retail pricing in the utility industry.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1995 was the addition of $27 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. See Statements of Cash Flows for additional information.
Capital Structure
As of December 31, 1995, the Company's capital structure consisted of 47.1 percent common equity, 9.8 percent preferred stock and 43.1 percent long-term debt, excluding amounts due within one year. The Company's long-term financial objective for capitalization ratios is to maintain a capital structure of common equity at 48 percent, preferred stock at 10 percent and debt at 42 percent.
In May 1995, the Company issued $15 million of first mortgage bonds maturing in 2025 and $20 million of term notes maturing in 1998. Maturities and retirements of long-term debt were $29 million in 1995, $5 million in 1994 and $4 million in 1993.
The composite interest rates and dividend rate for the years 1993 through 1995 as of year-end were as follows:
1995 1994 1993 ------------------------------- Composite interest rates on long-term debt 7.5% 8.0% 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 $86 million ($33 million in 1996, $30 million in 1997, and $23 million in 1998). 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.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $21.7 million will be needed by the end of 1998 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--has significantly impacted the Company and other subsidiaries of The 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 The Southern Company. As a result of The 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1995 Annual Report
emission allowance is the authority to emit one ton of sulfur dioxide during a calendar year. The method for issuing allowances is based on the fossil fuel consumed from 1985 through 1987 for each affected generating unit. Emission allowances are transferable and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the cost of compliance. The Southern Company's sulfur dioxide compliance strategy is designed to use allowances as a compliance option.
The 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. Compliance with nitrogen oxide emission limits was achieved by the installation of new control equipment at 22 of the original 28 affected generating units. Construction expenditures for Phase I compliance totaled approximately $320 million through 1995 for The Southern Company, of which the Company's portion was approximately $2 million.
For Phase II sulfur dioxide compliance, The Southern Company could use emission allowances banked during Phase I, increase fuel switching, install flue gas desulfurization equipment at selected plants, and/or purchase more allowances, depending on the price and availability of allowances. Also, in Phase II, equipment to control nitrogen oxide emissions will be installed on additional system fossil-fired plants as required to meet Phase II limits. Therefore, during the period 1996 to 2000, current compliance strategy could require total estimated construction expenditures of approximately $150 million for The Southern Company, of which the Company's portion is approximately $4.1 million. 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 0.7 percent in annual revenue requirements from customers could be necessary to fully recover the Company's costs 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.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The EPA is scheduled to submit a report to Congress on the results of this study during 1996. The report will include a decision on whether additional regulatory control of these substances is warranted. Compliance with any new control standards could result in significant additional costs. The impact of new standards--if any--will depend on the development and implementation of applicable regulations.
The EPA is evaluating the need to revise the ambient air quality standards for particulate matter and ozone. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In 1996, the EPA may issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes--coal ash and other utility wastes--as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1995 Annual Report
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 The Southern Company's operations. The full impact of these requirements cannot be determined at this time, pending the development and implementation of applicable regulations.
Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect The 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, 1995, the Company had $0.9 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, $16 million remained unused at December 31, 1995.
It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will also be derived from operations and the sale of additional first mortgage bonds and preferred stock and capital contributions from The 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 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 Savannah Electric and Power Company 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Savannah Electric and Power Company is a wholly owned subsidiary of The Southern Company, which is the parent company of five operating companies, a system service company, Southern Communications Services (Southern Communications), Southern Electric International (Southern Electric), 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 (SEC). The system service company provides, at cost, specialized services to The 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 Electric 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 The Southern Company's nuclear power plants. Southern Development develops new business opportunities related to energy products and services.
The Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both The 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:
1995 1994 --------------------------- (in thousands) Deferred income taxes $ 21,557 $ 23,521 Premium on reacquired debt 5,316 3,295 Deferred income tax credits (24,419) (25,487) - - --------------------------------------------------------------- Total $ 2,454 $ 1,329 ===============================================================
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. Revenues are adjusted for differences between recoverable fuel and demand-side management program 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 1995, uncollectible accounts continued to average less than 1 percent of revenues.
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NOTES (continued) Savannah Electric and Power Company 1995 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 2.9 percent in 1995, 1994 and 1993. 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 The 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 7.42 percent in 1995, 8.04 percent in 1994 and 8.77 percent in 1993.
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
In accordance with FASB Statement No. 107, Disclosure About Fair Value of Financial Instruments, the Company's financial instruments that the carrying amounts did not approximate fair value at December 31 were as follows:
Long-Term Debt -------------------------- Carrying Fair Year Amount Value - - ---- -------------------------- (in millions) 1995 $154 $165 1994 157 153 ==============================================================
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, 1995, the accumulated provision amounted to $0.3 million. Regulatory treatment by the GPSC allows the Company to accrue up to $0.6 million per year.
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NOTES (continued) Savannah Electric and Power Company 1995 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.
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 ------------------------ 1995 1994 ------------------------ (in thousands) Actuarial present value of benefit obligation: Vested benefits $38,169 $35,227 Non-vested benefits 2,585 2,069 - - ---------------------------------------------------------------- Accumulated benefit obligation 40,754 37,296 Additional amounts related to projected salary increases 7,786 7,393 - - ---------------------------------------------------------------- Projected benefit obligation 48,540 44,689 Less: Fair value of plan assets 36,836 27,165 Unrecognized net loss 9,606 10,950 Unrecognized prior service cost 1,375 1,510 Unrecognized net transition obligation 532 621 Adjustment required to recognize additional minimum liability 3,727 5,688 - - ---------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 3,918 $10,131 ================================================================
The weighted average rates assumed in the actuarial calculations for the pension plan were:
1995 1994 1993 ------------------------ Discount 7.25% 8.00% 7.50% Annual salary increase 4.75 5.25 4.75 Long-term return on plan assets 8.75 9.00 9.25 ============================================================
In accordance with Statement No. 87, an additional liability related to under-funded accumulated benefit obligations was reflected at December 31, 1995 and December 31, 1994. Corresponding net-of-tax balances of $0.1 million and $0.5 million were recognized as separate components of Common Stock Equity in the 1995 and 1994 Statements of Capitalization.
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NOTES (continued) Savannah Electric and Power Company 1995 Annual Report
Postretirement Benefits ------------------------ 1995 1994 ------------------------ (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $13,560 $10,994 Employees eligible to retire 1,471 884 Other employees 5,966 8,485 - - ------------------------------------------------------------- Accumulated benefit obligation 20,997 20,363 Less: Fair value of plan assets 1,443 393 Unrecognized net loss 5,719 3,197 Unrecognized transition obligation 9,135 13,021 - - ------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 4,700 $ 3,752 =============================================================
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:
1995 1994 ------------------ Discount 7.25% 8.00% Annual salary increase 4.75 5.50 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 9.8 percent for 1995, decreasing gradually to 5.3 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, 1995, by $1.3 million and the aggregate of the service and interest cost components of the net postretirement cost by $0.2 million.
Components of the plans' net costs are shown below:
Pension ------------------------------ 1995 1994 1993 ------------------------------ (in thousands) Benefits earned during the year $1,188 $1,192 $1,188 Interest cost on projected benefit obligation 3,395 3,279 2,741 Actual (return) loss on plan assets (5,791) 27 (2,199) Net amortization and deferral 4,125 (1,474) 716 - - -------------------------------------------------------------------- Net pension cost $2,917 $3,024 $2,446 ====================================================================
Of the above net pension costs, $2.4 million in 1995, $2.6 million in 1994 and $2.0 million in 1993 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits ------------------------------ 1995 1994 1993 ------------------------------ (in thousands) Benefits earned during the year $ 504 $ 632 $ 443 Interest cost on accumulated benefit obligation 1,638 1,492 1,134 Amortization of transition obligation 723 723 723 Actual (return) loss on plan assets (34) 6 - Net amortization and deferral 93 111 - - - -------------------------------------------------------------------- Net postretirement costs $2,924 $2,964 $2,300 ====================================================================
Of the above net postretirement costs, $2.4 million in 1995, $2.4 million in 1994 and $1.8 million in 1993 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
The Company has a supplemental retirement plan for certain executive employees. The plan is unfunded and payable from the general funds of the Company. The Company has purchased life insurance on participating executives, and plans to use these policies to satisfy this obligation. Benefit costs associated with this plan for 1995, 1994 and 1993 were $0.4 million, $0.4 million and $1.0 million, respectively. The 1993 benefit costs reflect a one-time expense related to employees who were part of the work force reduction program.
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NOTES (continued) Savannah Electric and Power Company 1995 Annual Report
Work Force Reduction Program
In 1993, the Company incurred additional costs for a one-time charge related to the implementation of a work force reduction program. In 1993, $4.5 million was charged to operating expenses and $0.6 million was charged to other income (expense).
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. The Company will refund to customers approximately $0.2 million which had been overcollected from the rate riders as of December 31, 1995.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently estimated to total $33 million in 1996, $30 million in 1997 and $23 million in 1998. The estimates include AFUDC of $1.0 million in 1996, $0.9 million in 1997 and $0.2 million in 1998. 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 construction of two combustion turbine peaking units totaling 160 megawatts was completed during 1994. The Company does not have any new 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 The 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 beginning of 1996, unused credit arrangements with five banks totaled $20.5 million and expire at various times during 1996.
The Company's revolving credit arrangements of $20 million, of which $16 million remained unused as of December 31, 1995, 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.
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NOTES (continued) Savannah Electric and Power Company 1995 Annual Report
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $1.3 million for 1995 and $1.5 million for 1994 and 1993. 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 the Company's generating plants.
At December 31, 1995, estimated future minimum lease payments for non-cancelable operating leases were as follows:
Amounts -------------------- (in millions) 1996 $1.6 1997 1.4 1998 1.1 1999 0.5 2000 0.5 2001 and thereafter 8.4 =============================================================
6. LONG-TERM POWER SALES AGREEMENTS
The operating subsidiaries of The Southern Company, including the 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. The agreements for non-firm capacity expired in 1994. Other agreements are firm and pertain to capacity related to specific generating units. Because energy is generally sold at cost under these agreements, revenues from capacity sales primarily affect profitability. The Company's portion of capacity revenues has been as follows:
Unit Other Year Power Long-Term Total - - ----------- ----------------------------------------- (in thousands) 1995 $3 $ - $ 3 1994 3 445 448 1993 2 976 978 ===============================================================
7. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption resulted in the recording of additional deferred income taxes and related regulatory assets and liabilities. At December 31, 1995, the tax-related regulatory assets and liabilities were $22 million and $24 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:
1995 1994 1993 -------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $10,427 $11,736 $11,663 Deferred -- current year 5,290 2,106 1,906 -- reversal of prior years (1,661) (755) (1,383) - - ----------------------------------------------------------------- 14,056 13,087 12,186 - - ----------------------------------------------------------------- State -- Currently payable 1,941 2,064 2,049 Deferred -- current year 695 188 119 -- reversal of prior years 35 86 (35) - - ----------------------------------------------------------------- 2,671 2,338 2,133 - - ----------------------------------------------------------------- Total 16,727 15,425 14,319 Less income taxes charged (credited) to other income (651) (864) (1,117) - - ----------------------------------------------------------------- Federal and state income taxes charged to operations $17,378 $16,289 $15,436 =================================================================
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
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NOTES (continued) Savannah Electric and Power Company 1995 Annual Report
1995 1994 --------- ---------- Deferred tax liabilities: (in thousands) Accelerated depreciation $62,822 $57,830 Property basis differences 11,330 12,956 Other 1,511 2,449 - - ---------------------------------------------------------------- Total 75,663 73,235 - - ---------------------------------------------------------------- Deferred tax assets: Pension and other benefits 3,660 4,816 Other 3,818 3,959 - - ---------------------------------------------------------------- Total 7,478 8,775 - - ---------------------------------------------------------------- Net deferred tax liabilities 68,185 64,460 Portions included in current assets, net 5,967 6,326 - - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $74,152 $70,786 ================================================================
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 1995, 1994 and 1993. At December 31, 1995, 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:
1995 1994 1993 ---------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of federal income tax benefit 4 4 4 Other - - (1) ------------------------------------------------------------- Effective income tax rate 39% 39% 38% =============================================================
The 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.
8. CUMULATIVE PREFERRED STOCK
In 1993, the Company issued 1,400,000 shares of 6.64% Series Preferred Stock which has redemption provisions of $26.66 per share plus accrued dividends if 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.
9. 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 1995, the Company issued $15 million of first mortgage bonds maturing in 2025 and $20 million of term notes maturing in 1998. Using the proceeds from such sales, the Company redeemed in June 1995 all of its remaining outstanding 9 1/4% Series First Mortgage Bonds due October 2019.
The sinking fund requirements of first mortgage bonds were satisfied by cash redemption in 1994 and 1995. Sinking fund requirements and/or maturities through 2000 applicable to long-term debt are as follows: $1.4 million in 1996; $0.2 million in 1997; $20.1 million in 1998; and no requirements in 1999 and 2000.
Details of pollution control obligations and other long-term debt at December 31 are as follows:
1995 1994 --------------------- (in thousands)
Collateralized obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds -- Variable rate (5.15% at 1/1/96) due 2016 $ 4,085 $ 4,085 6 3/4% due 2022 13,870 13,870 Capital lease obligations -- Combustion turbine equipment - 980 Transportation fleet 485 508 Notes Payable -- 6.04% due 1995 - 3,500 6.035% due 1995 - 5,000 Variable rate (5.85% at 1/1/96) due 1998 15,000 Variable rate (5.84% at 1/1/96) due 1998 5,000 - - ---------------------------------------------------------------- Total $38,440 $27,943 ================================================================
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NOTES (continued) Savannah Electric and Power Company 1995 Annual Report
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.
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.
10. 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:
1995 1994 ---------------------- (in thousands) Bond sinking fund requirement $1,200 $1,350 Less: Portion to be satisfied by certifying property additions - - - - -------------------------------------------------------------------- Cash sinking fund requirement 1,200 1,350 Other long-term debt maturities (Note 9) 207 1,229 - - -------------------------------------------------------------------- Total $1,407 $2,579 ====================================================================
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. In January 1996, the Company satisfied its 1996 sinking fund requirement of $1.2 million by cash redemption.
11. 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, 1995, approximately $62 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Indenture.
12. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1995 and 1994 are as follows (in thousands):
Net Income After Operating Operating Dividends on Quarter Ended Revenue Income Preferred Stock - - ------------------- ------------ ------------ -------------------
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
March 1994 $46,717 $ 7,130 $ 3,898 June 1994 56,377 9,555 6,051 September 1994 63,674 13,495 9,547 December 1994 45,017 5,989 2,614 =================================================================
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
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SAVANNAH ELECTRIC AND POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1995
First Mortgage Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1993 $ 20,000 6-3/8% $ 20,000 7/1/03 1991 30,000 9-3/8% 29,400 7/1/21 1992 30,000 8.30% 30,000 7/1/22 1993 25,000 7.40% 25,000 7/1/23 1995 15,000 7-7/8% 15,000 5/1/25 ============ =========== $ 120,000 $ 119,400 ============ ===========
Pollution Control Bonds Amount Interest Amount Series Issued Rate Outstanding Maturity - - -------------------------------------------------------------------------------- (Thousands) (Thousands) 1993 $ 4,085 Variable $ 4,085 1/1/16 1992 13,870 6-3/4% 13,870 2/1/22 ============ =========== $ 17,955 $ 17,955 ============ ===========
Preferred Stock Shares Dividend Amount Series Outstanding Rate Outstanding - - ---------------------------------------------------------------------- (Thousands) 1993 1,400,000 6.64% $ 35,000
SECURITIES RETIRED DURING 1995
First Mortgage Bonds Principal Interest Series Amount Rate - - ---------------------------------------------------------------------- (Thousands) 1989 $ 28,950 9-1/4% 1991 300 9-3/8% ============ $ 29,250 ============
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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 1996 annual meeting of stockholders. The ages of directors and executive officers in Item 10

Item 10 set forth below are as of December 31, 1995.
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 56 Served as Director since 3-1-89
Bill M. Guthrie Executive Vice President Age 62 Served as Director since 12-16-88
Whit Armstrong (2) Age 48 Served as Director since 9-24-82
Philip E. Austin (2) Age 53 Served as Director since 1-25-91
Margaret A. Carpenter (2) Age 71 Served as Director since 2-26-93
A. W. Dahlberg (2) Age 55 Served as Director since 4-22-94
Peter V. Gregerson, Sr. (2) Age 67 Served as Director since 10-22-93
Carl E. Jones, Jr. (2) Age 55 Served as Director since 4-22-88
Wallace D. Malone, Jr. (2) Age 59 Served as Director since 6-22-90
William V. Muse (2) Age 56 Served as Director since 2-26-93
John T. Porter (2) Age 64 Served as Director since 10-22-93
Gerald H. Powell (2) Age 69 Served as Director since 2-28-86
Robert D. Powers (2) Age 45 Served as Director since 1-24-92
John W. Rouse (2) Age 58 Served as Director since 4-22-88
William J. Rushton, III (2) Age 66 Served as Director since 9-18-70
James H. Sanford (2) Age 51 Served as Director since 8-1-83
John C. Webb, IV (2) Age 53 Served as Director since 4-22-77
John W. Woods (2) Age 64 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 28, 1995) for one year until the next annual meeting or until a successor is elected and qualified.
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There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of ALABAMA acting solely in their capacities as such.
Identification of executive officers of ALABAMA.
Elmer B. Harris (1) President, Chief Executive Officer and Director Age 56 Served as Executive Officer since 3-1-89
Banks H. Farris Executive Vice President Age 60 Served as Executive Officer since 12-3-91
William B. Hutchins, III Executive Vice President and Chief Financial Officer Age 52 Served as Executive Officer since 12-3-91
Charles D. McCrary Executive Vice President Age 44 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 28, 1995) 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 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.
Philip E. Austin - Chancellor, The University of Alabama System. Previously President and Chancellor of Colorado State University.
Margaret A. Carpenter - President, Compos-it, Inc. (typographics), Montgomery, Alabama.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of SOUTHERN effective March 1, 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, Protective Life Corporation and Equifax, Inc. and a nominee for election as a director of SunTrust Banks, Inc.
Peter V. Gregerson, Sr. - Chairman Emeritus of Gregerson's Foods, Inc. (retail groceries), Gadsden, Alabama.
Carl E. Jones, Jr. - Chairman and Chief Executive Officer of First Alabama Bank, Mobile, Alabama.
Wallace D. Malone, Jr. - Chairman and Chief Executive Officer of SouthTrust Corporation, bank holding company, Birmingham, Alabama.
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William V. Muse - President of Auburn University. He previously served as President of the University of Akron from 1984 to 1992. Director of Alabama National Bancorporation, Shoal Creek, Alabama.
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, 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.
John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber), Demopolis, Alabama.
John W. Woods - Effective January 1996, Chairman, AmSouth Bancorporation (multi-bank holding company), Birmingham, Alabama. He previously served as Chairman and Chief Executive Officer of AmSouth Bancorporation. Director of Protective Life Corporation.
Banks H. Farris - Elected in 1991; responsible primarily for providing the overall management of the Human Resources, Information Resources, Power Delivery and Marketing Departments and the six geographic divisions. He previously served as Senior Vice President from 1991 to 1994 and Vice President - Human Resources from 1989 to 1991.
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 and Vice President and Treasurer from 1983 to 1991.
Charles D. McCrary - Elected in 1991; responsible for the External Relations Department, Operating Services and Corporate Services. He previously served as Senior Vice President from 1991 to 1994 and Vice President of Administrative Services - Nuclear of SCS from 1988 to 1991.
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 51 Served as Director since 1-1-94
Warren Y. Jobe Executive Vice President, Treasurer and Chief Financial Officer Age 55 Served as Director since 8-1-82
Bennett A. Brown (1) Age 66 Served as Director since 5-15-80
A. W. Dahlberg (1) Age 55 Served as Director since 6-1-88
William A. Fickling, Jr. (1) Age 63 Served as Director since 4-18-73
L. G. Hardman III (1) Age 56 Served as Director since 6-25-79
James R. Lientz, Jr. (1) Age 52 Served as Director since 7-21-93
William A. Parker, Jr. (1) Age 68 Served as Director since 5-19-65
G. Joseph Prendergast (1) Age 50 Served as Director since 1-20-93
Herman J. Russell (1) Age 65 Served as Director since 5-18-88
Gloria M. Shatto (1) Age 64 Served as Director since 2-20-80
William Jerry Vereen (1) Age 55 Served as Director since 5-18-88
Carl Ware (1) (2) Age 52 Served as Director since 2-15-95
Thomas R. Williams (1) Age 67 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 17, 1995) 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 51 Served as Executive Officer since 1-1-94
Warren Y. Jobe Executive Vice President, Treasurer, Chief Financial Officer and Director Age 55 Served as Executive Officer since 5-19-82
William C. Archer, III Executive Vice President - External Affairs Age 47 Served as Executive Officer since 4-6-95
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W. G. Hairston, III Executive Vice President - Nuclear Age 51 Served as Executive Officer since 6-1-93
Gene R. Hodges Executive Vice President - Customer Operations Age 57 Served as Executive Officer since 11-19-86
William P. Bowers Senior Vice President - Marketing Age 39 Served as Executive Officer since 9-22-95
Wayne T. Dahlke Senior Vice President - Power Delivery Age 54 Served as Executive Officer since 4-19-89
James K. Davis Senior Vice President - Corporate Relations Age 55 Served as Executive Officer since 10-1-93
Robert H. Haubein Senior Vice President - Fossil/Hydro Power Age 55 Served as Executive Officer since 2-19-92
Fred D. Williams Senior Vice President - Wholesale Power Marketing Age 51 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 17, 1995) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Bowers whose election was effective on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of GEORGIA acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
H. Allen Franklin - President and Chief Executive Officer since 1994. He previously served as President and Chief Executive Officer of SCS from 1988 through 1993. Director of SOUTHERN and SouthTrust Corporation.
Warren Y. Jobe - Executive Vice President and Chief Financial Officer since 1982 and Treasurer 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 effective March 1, 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, Protective Life Corporation and Equifax, Inc. and a nominee for election as a director of 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, Life Insurance Company of Georgia, Atlantic Realty Company, ING North America Insurance 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 and President of Wachovia Corporate Services, Inc.
Herman J. Russell - Chairman of the Board and Chief Executive Officer, 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.
Gloria M. Shatto - President, Berry College, Mount Berry, Georgia. Director of SOUTHERN, Becton Dickinson & Company, Kmart Corporation 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; Senior Vice President, The Coca-Cola Co.
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 since 1992. Senior Vice President - Region/Land Operations from 1990 to 1992.
William P. Bowers - Senior Vice President - Marketing since September 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 August 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 57 Served as Director since 2-1-94
Reed Bell, Sr., M.D. (1) Age 69 Served as Director since 1-17-86
Paul J. DeNicola (1) Age 47 Served as Director since 4-19-91
Fred C. Donovan (1) Age 55 Served as Director since 1-18-91
W. D. Hull, Jr. (1) Age 63 Served as Director since 10-14-83
C. W. Ruckel (1) Age 68 Served as Director since 4-20-62
J. K. Tannehill (1) Age 62 Served as Director since 7-19-85
(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 27, 1995) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GULF acting solely in their capacities as such.
Identification of executive officers of GULF.
Travis J. Bowden President, Chief Executive Officer and Director Age 57 Served as Executive Officer since 2-1-94
F. M. Fisher, Jr. Vice President - Employee and External Relations Age 47 Served as Executive Officer since 5-19-89
John E. Hodges, Jr. Vice President - Customer Operations Age 52 Served as Executive Officer since 5-19-89
G. Edison Holland, Jr. Vice President - Power Generation/Transmission and Corporate Counsel Age 43 Served as Executive Officer since 4-25-92
A. E. Scarbrough Vice President - Finance Age 59 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 21, 1995) 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.
Reed Bell, Sr., M.D. - Medical Doctor and since 1989, employee of the State of Florida. He serves as Medical Director of Children's Medical Services, District 1. He previously served as Medical Director of the Escambia County Public Health Unit until 1992.
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 and President and Chief Executive Officer of MISSISSIPPI from 1989 to 1991. 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. D. 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.
C. W. Ruckel - Chairman of the Board of The Vanguard Bank and Trust Company, Valparaiso, Florida. President and owner of Ruckel Properties, Inc., Valparaiso, Florida.
J. K. Tannehill - President and Chief Executive Officer of Merrick International Industries, Lynn Haven, Florida. He previously served as President and Chief Executive Officer of Stock Equipment Company, Chagrin Falls, Ohio, until 1991. Director of Florida First Bank, Panama City, Florida.
F. M. Fisher, Jr. - Elected Vice President - Employee and External Relations in 1989.
John E. Hodges, Jr. - Elected Vice President - Customer Operations in 1989. 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 March 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.
A. 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 47 Served as Director since 3-27-95
Paul J. DeNicola (1) Age 47 Served as Director since 5-1-89
Edwin E. Downer (1) Age 64 Served as Director since 4-24-84
Robert S. Gaddis (1) Age 64 Served as Director since 1-21-86
Walter H. Hurt, III (1) Age 60 Served as Director since 4-6-82
Aubrey K. Lucas (1) Age 61 Served as Director since 4-24-84
George A. Schloegel (1) Age 55 Served as Director since 7-26-95
Philip J. Terrell (1) Age 42 Served as Director since 2-22-95
N. Eugene Warr (1) Age 60 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 4, 1995) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Schloegel 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 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 47 Served as Executive Officer since 3-27-95
H. E. Blakeslee Vice President - Customer Services and Marketing Age 55 Served as Executive Officer since 1-25-84
F. D. Kuester Vice President - Power Generation and Delivery Age 45 Served as Executive Officer since 3-28-94
Don E. Mason Vice President - External Affairs and Corporate Services Age 54 Served as Executive Officer since 7-27-83
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer Age 43 Served as Executive Officer since 1-1-95
Each of the above is currently an executive officer of MISSISSIPPI, serving a term running from the last annual meeting of the directors (April 26, 1995) 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 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 March 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. He previously served as President and Chief Executive Officer of MISSISSIPPI from 1989 to 1991. Director of SOUTHERN, SAVANNAH and GULF.
Edwin E. Downer - Business consultant specializing in economic analysis, management controls and procedural studies.
Robert S. Gaddis - President of the 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 of 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, Hancock Bank - Louisiana and First National Bank of Denham Springs, 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). He previously served as Vice Chairman of the Board of SouthTrust Bank of Mississippi, formerly The Jefferson Bank, Biloxi, Mississippi, from 1977 to 1995.
H. E. Blakeslee - Elected Vice President in 1984. Primarily responsible for business development, rates and wholesale marketing, technical research, district operations and the customer services center.
F. D. Kuester - Elected Vice President in 1994. Primarily responsible for generating plants, environmental quality, fuel services, power generation technical services, distribution, 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 and general services, as well as the human resources function.
Michael W. Southern - Elected Vice President, Secretary, Treasurer and Chief Financial Officer in 1995, responsible primarily for accounting, treasury, finance, materials 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 63 Served as Director since 9-1-82
Helen Quattlebaum Artley (1) Age 68 Served as Director since 5-17-77
Paul J. DeNicola (1) Age 47 Served as Director since 3-14-91
Brian R. Foster (1) Age 46 Served as Director since 5-16-89
Walter D. Gnann (1) Age 60 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 50 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 59 Served as Director since 5-17-77
Frederick F. Williams, Jr. (1) Age 68 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 16, 1995) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he/she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of SAVANNAH acting solely in their capacities as such.
Identification of executive officers of SAVANNAH.
Arthur M. Gignilliat, Jr. President, Chief Executive Officer and Director Age 63 Served as Executive Officer since 2-15-72
W. Miles Greer Vice President - Marketing and Customer Services Age 52 Served as Executive Officer since 11-20-85
Larry M. Porter Vice President - Operations Age 50 Served as Executive Officer since 7-1-91
Kirby R. Willis Vice President, Treasurer and Chief Financial Officer Age 44 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 19, 1995) 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.
III-11
Paul J. DeNicola - President and Chief Executive Officer of SCS since 1994. Executive Vice President of SCS from 1991 through 1993. He previously served as President and Chief Executive Officer of MISSISSIPPI from 1989 to 1991. Director of SOUTHERN, GULF and MISSISSIPPI.
Brian R. Foster - President and Chief Executive Officer of NationsBank of Georgia, N.A., in Savannah since 1988.
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. Previously he served as Assistant Plant Manager of GEORGIA's Plant Scherer from 1984 to 1991.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since 1994. Responsible for all financial activities, Information Resources, Human Resources, Corporate Services, and Environmental Affairs and Safety. He previously served as Treasurer, Controller and Assistant Secretary from 1991 to 1993 and Treasurer and Secretary from 1987 to 1991.
Involvement in certain legal proceedings. None.
III-12
ITEM 11.

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 1995 for each of the operating affiliates (ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH).
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III-14
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III-16
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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 1995 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, 1995, the applicable compensation levels and years of accredited service are presented in the following tables:
III-25
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.
The following table sets forth the estimated annual pension benefits under the pension plan in effect during 1995 which are payable by SAVANNAH to employees upon retirement at the normal retirement age after designated periods of accredited service and at a specified compensation level.
- - -------------------- 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, 1995, the applicable compensation levels and years of accredited service are presented in the following table:-
Deferred Compensation Plan; Supplemental Executive Retirement Plan.
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 which became effective January 1, 1984. 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.
- - -------------------- 2 The plan benefits are subject to the maximum benefit limitations set forth in Section 415 of the Internal Revenue Code.
III-27
Compensation of Directors.
Standard Arrangements. The following table presents compensation paid to the directors, during 1995 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.
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH also provide retirement benefits to non-employee directors who are credited with a minimum of 60 months of service on the board of directors of one or more system companies, under the Outside Directors Pension Plan. Eligible directors are entitled to benefits under the Plan 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 to 100 percent of the annual retainer fee in effect on the date of retirement. 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, 1995 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 and Chief Executive Officer of AmSouth Bancorporation during 1995.
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ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security ownership of certain beneficial owners. SOUTHERN is the beneficial owner of 100% of the outstanding common stock of 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, 1995. 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, 1995.
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III-31
III-32
III-33
III-34
III-35
Item 13.

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 Chairman and Chief Executive Officer of First Alabama Bank, Mobile, Alabama; Mr. Wallace D. Malone is Chairman and Chief Executive Officer of SouthTrust Corporation, Birmingham, Alabama, and Mr. John W. Woods is Chairman of AmSouth Bancorporation, Birmingham, Alabama, and during 1995, Mr. Woods also served as Chief Executive Officer of AmSouth Bancorporation. During 1995, 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 1995, 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 1995, GEORGIA leased a building from Riverside Manufacturing Co. for approximately $75,000. 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. D. Hull, Jr. is Vice Chairman of SunTrust Bank, West Florida, Panama City, Florida, and Mr. C. W. Ruckel is Chairman of the Board of The Vanguard Bank and Trust Company, Valparaiso, Florida. During 1995, these banks 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 banks in the future.
The firm of Beggs & Lane, P.A. serves as local counsel for GULF and received from GULF approximately $1,034,573 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 President of Trustmark National Bank, Laurel, Mississippi; Mr. George A. Schloegel is President of Hancock Bank, Gulfport, Mississippi; and during 1995, Mr. N. Eugene Warr served as Vice Chairman of the Board of SouthTrust Bank of Mississippi, Biloxi, Mississippi. During 1995, these banks furnished a number of regular banking services in the ordinary course of business to MISSISSIPPI. MISSISSIPPI intends to maintain normal banking relations with the aforesaid banks in the future.
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Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
SAVANNAH
Transactions with management and others.
Mr. Brian R. Foster is President and Chief Executive Officer of NationsBank of Georgia, N.A., in Savannah, Georgia. During 1995, this bank furnished a number of regular banking services in the ordinary course of business to SAVANNAH. SAVANNAH intends to maintain normal banking relations with the aforesaid bank in the future.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
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PART IV
Item 14.

Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form 10-K:
(1) Financial Statements:
Reports of Independent Public Accountants on the financial statements for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed under Item 8 herein.
The financial statements filed as a part of this report for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed under Item 8 herein.
(2) Financial Statement Schedules:
Reports of Independent Public Accountants as to Schedules for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are included herein on pages IV-12 through IV-17.
Financial Statement Schedules for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed in the Index to the Financial Statement Schedules at page S-1.
(3) Exhibits:
Exhibits for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed in the Exhibit Index at page E-1.
(b) Reports on Form 8-K: During the fourth quarter of 1995, SOUTHERN filed the following Current Reports on Form 8-K and Form 8-K/A:
Form 8-K filed October 3, 1995: Items reported: Item 2 Item 7 Financial statements filed: SWEB Consolidated Balance Sheet at March 31, 1995 SWEB Consolidated Profit and Loss Account Statement for the Year Ended March 31, 1995 SWEB Consolidated Statement of Cash Flows for the Year Ended March 31, 1995
Form 8-K/A filed November 20, 1995: Item reported: Item 7 Financial statements filed: SOUTHERN and Subsidiary Companies Condensed Balance Sheet at September 30, 1995, incorporated by reference to Form 10-Q for the Quarter Ended September 30, 1995
SOUTHERN and Subsidiary Companies Pro Forma Condensed Consolidated Statements of Income (Unaudited) for the Nine Months Ended September 30, 1995 and for the Twelve Months Ended December 31, 1995
IV-1
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
THE SOUTHERN COMPANY
By: A. W. Dahlberg, Chairman, President and Chief Executive Officer
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
A. W. Dahlberg Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
W. L. Westbrook Financial Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)
Directors: John C. Adams Elmer B. Harris A. D. Correll William A. Parker, Jr. Paul J. DeNicola William J. Rushton, III Jack Edwards Gloria M. Shatto H. Allen Franklin Gerald J. St. Pe' Bruce S. Gordon Herbert Stockham L. G. Hardman III
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ALABAMA POWER COMPANY
By: Elmer B. Harris, President and Chief Executive Officer
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Elmer B. Harris President, Chief Executive Officer and Director (Principal Executive Officer)
William B. Hutchins, III Executive Vice President and Chief Financial Officer (Principal Financial Officer)
David L. Whitson Vice President and Comptroller (Principal Accounting Officer)
Directors: Whit Armstrong William V. Muse Philip E. Austin John T. Porter Margaret A. Carpenter Gerald H. Powell A. W. Dahlberg Robert D. Powers Peter V. Gregerson, Sr. John W. Rouse Bill M. Guthrie James H. Sanford Carl E. Jones, Jr. John Cox Webb, IV Wallace D. Malone, Jr. John W. Woods
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
GEORGIA POWER COMPANY
By: H. Allen Franklin, President and Chief Executive Officer
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
H. Allen Franklin President, Chief Executive Officer and Director (Principal Executive Officer)
Warren Y. Jobe Executive Vice President, Treasurer, Chief Financial Officer and Director (Principal Financial Officer)
Cliff S. Thrasher Vice President, Comptroller and Chief Accounting Officer (Principal Accounting Officer)
Directors: Bennett A. Brown G. Joseph Prendergast A. W. Dahlberg Herman J. Russell William A. Fickling, Jr. Gloria M. Shatto L. G. Hardman III William Jerry Vereen James R. Lientz, Jr. Thomas R. Williams
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
GULF POWER COMPANY
By: Travis J. Bowden, President and Chief Executive Officer
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Travis J. Bowden President, Chief Executive Officer and Director (Principal Executive Officer)
A. E. Scarbrough Vice President - Finance (Principal Financial and Accounting Officer)
Directors: Reed Bell, Sr., M.D. W. D. Hull, Jr. Paul J. DeNicola C. W. Ruckel Fred C. Donovan J. K. Tannehill
By: /S/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
IV-3
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
MISSISSIPPI POWER COMPANY
By: Dwight H. Evans, President and Chief Executive Officer
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Dwight H. Evans President, Chief Executive Officer and Director (Principal Executive Officer)
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Paul J. DeNicola Aubrey K. Lucas Edwin E. Downer George A. Schloegel Robert S. Gaddis Philip J. Terrell Walter H. Hurt, III N. Eugene Warr
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SAVANNAH ELECTRIC AND POWER COMPANY
By: Arthur M. Gignilliat, Jr., President and Chief Executive Officer
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Arthur M. Gignilliat, Jr. President, Chief Executive Officer and Director (Principal Executive Officer)
Kirby R. Willis Vice President, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Helen Q. Artley Robert B. Miller, III Paul J. DeNicola Arnold M. Tenenbaum Brian R. Foster Frederick F. Williams, Jr. Walter D. Gnann
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 22, 1996
IV-4
Exhibit 21. Subsidiaries of the Registrants.*
Jurisdiction of Name of Company Organization ------------------------------------------------ --------------------- Alabama Power Company Alabama Alabama Power Capital Trust I Delaware Alabama Property Company Alabama Southern Electric Generating Company Alabama Georgia Power Company Georgia Piedmont-Forrest Corporation Georgia Georgia Power L.P. Holdings Corp. Georgia Georgia Power Capital, L.P. Delaware Southern Electric Generating Company Alabama Gulf Power Company Maine Mississippi Power Company Mississippi Savannah Electric and Power Company Georgia SEI Holdings, Inc. Delaware ------------------------------------------------ ---------------------
*This list omits certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K Item 601.
IV-5
ARTHUR ANDERSEN LLP
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 21, 1996 on the financial statements of The Southern Company and its subsidiaries and the related financial statement schedules, included in this Form 10-K, into The Southern Company's previously filed Registration Statement File Nos. 2-78617, 33-3546, 33-23152, 33-30171, 33-51433, 33-54415, 33-57951, 33-58371, and 33-60427.
/s/Arthur Andersen LLP
Atlanta, Georgia March 20, 1996
IV-6
ARTHUR ANDERSEN LLP
Exhibit 23(b)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 21, 1996 on the financial statements of Alabama Power Company and the related financial statement schedules, included in this Form 10-K, into Alabama Power Company's previously filed Registration Statement File Nos. 33-49653 and 33-61845.
/s/Arthur Andersen LLP
Birmingham, Alabama March 20, 1996
IV-7
ARTHUR ANDERSEN LLP
Exhibit 23(c)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 21, 1996 on the financial statements of Georgia Power Company and the related financial statement schedules, included in this Form 10-K, into Georgia Power Company's previously filed Registration Statement File Nos. 33-49661 and 33-60345.
/s/Arthur Andersen LLP
Atlanta, Georgia March 20, 1996
IV-8
ARTHUR ANDERSEN LLP
Exhibit 23(d)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 21, 1996 on the financial statements of Gulf Power Company and the related financial statement schedules, included in this Form 10-K, into Gulf Power Company's previously filed Registration Statement File No. 33-50165.
/s/Arthur Andersen LLP
Atlanta, Georgia March 20, 1996
IV-9
ARTHUR ANDERSEN LLP
Exhibit 23(e)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 21, 1996 on the financial statements of Mississippi Power Company and the related financial statement schedules, included in this Form 10-K, into Mississippi Power Company's previously filed Registration Statement File Nos. 33-49320 and 33-49649.
/s/Arthur Andersen LLP
Atlanta, Georgia March 20, 1996
IV-10
ARTHUR ANDERSEN LLP
Exhibit 23(f)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 21, 1996 on the financial statements of Savannah Electric and Power Company and the related financial statement schedules, included in this Form 10-K, into Savannah Electric and Power Company's previously filed Registration Statement File No. 33-52509.
/s/Arthur Andersen LLP
Atlanta, Georgia March 20, 1996
IV-11
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To The Southern Company:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements of The Southern Company and its subsidiaries included in this Form 10-K, and have issued our report thereon dated February 21, 1996. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to The Southern Company and its subsidiaries (page S-2) is the responsibility of The Southern Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
IV-12
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Alabama Power Company:
We have audited in accordance with generally accepted auditing standards, the financial statements of Alabama Power Company included in this Form 10-K, and have issued our report thereon dated February 21, 1996. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Alabama Power Company (page S-3) is the responsibility of Alabama Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/Arthur Andersen LLP
Birmingham, Alabama February 21, 1996
IV-13
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Georgia Power Company:
We have audited in accordance with generally accepted auditing standards, the financial statements of Georgia Power Company included in this Form 10-K, and have issued our report thereon dated February 21, 1996. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Georgia Power Company (page S-4) is the responsibility of Georgia Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
IV-14
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Gulf Power Company:
We have audited in accordance with generally accepted auditing standards, the financial statements of Gulf Power Company included in this Form 10-K, and have issued our report thereon dated February 21, 1996. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Gulf Power Company (page S-5) is the responsibility of Gulf Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
IV-15
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Mississippi Power Company:
We have audited in accordance with generally accepted auditing standards, the financial statements of Mississippi Power Company included in this Form 10-K, and have issued our report thereon dated February 21, 1996. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Mississippi Power Company (page S-6) is the responsibility of Mississippi Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
IV-16
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Savannah Electric and Power Company:
We have audited in accordance with generally accepted auditing standards, the financial statements of Savannah Electric and Power Company included in this Form 10-K, and have issued our report thereon dated February 21, 1996. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Savannah Electric and Power Company (page S-7) is the responsibility of Savannah Electric and Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia February 21, 1996
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves 1995, 1994 and 1993 The Southern Company and Subsidiary Companies............ S-2 Alabama Power Company.................................... S-3 Georgia Power Company.................................... S-4 Gulf Power Company....................................... S-5 Mississippi Power Company................................ S-6 Savannah Electric and Power Company...................... S-7
Schedules I through V not listed above are omitted as not applicable or not required. Columns omitted from schedules filed have been omitted because the information is not applicable or not required.
S-1
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 (Stated in Thousands of Dollars)
S-2
ALABAMA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 (Stated in Thousands of Dollars)
S-3
GEORGIA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 (Stated in Thousands of Dollars)
S-4
GULF POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 (Stated in Thousands of Dollars)
S-5
MISSISSIPPI POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 (Stated in Thousands of Dollars)
S-6
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 (Stated in Thousands of Dollars)
S-7
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC, respectively, as the exhibits and in the file numbers indicated and are incorporated herein by reference. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 601 of Regulation S-K of the SEC, immediately precedes the exhibits being physically filed with this Form 10-K.
(1) Underwriting Agreements
GEORGIA
* (c) - Distribution Agreement dated November 29, 1995 between GEORGIA and Lehman Brothers Inc.; Donaldson, Lufkin & Jenrette Securities Corporation; J. P. Morgan Securities Inc.; Salomon Brothers Inc and Smith Barney Inc. relating to $300,000,000 First Mortgage Bonds Secured Medium-Term Notes.
(3) Articles of Incorporation and By-Laws
SOUTHERN
(a) 1 - Composite Certificate of Incorporation of SOUTHERN, reflecting all amendments thereto through January 5, 1994. (Designated in Registration No. 33-3546 as Exhibit 4(a), in Certificate of Notification, File No. 70-7341, as Exhibit A and in Certificate of Notification, File No. 70-8181, as Exhibit A.)
(a) 2 - By-laws of SOUTHERN as amended effective October 21, 1991, and as presently in effect. (Designated in Form U-1, File No. 70-8181, as Exhibit A-2.)
ALABAMA
(b) 1 - Charter of ALABAMA and amendments thereto through October 14, 1994. (Designated in Registration Nos. 2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a) and in Certificate of Notification, File No. 70-8191, as Exhibit A.)
(b) 2 - By-laws of ALABAMA as amended effective July 23, 1993, and as presently in effect. (Designated in Form U-1, File No. 70-8191, as Exhibit A-2.)
GEORGIA
(c) 1 - Charter of GEORGIA and amendments thereto through October 25, 1993. (Designated in Registration Nos. 2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141
as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in GEORGIA's Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992, File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No. 1-6468, as Exhibit 4(b) and in Form 8-K dated October 20, 1993, File No. 1-6468, as Exhibit 4(b).)
(c) 2 - By-laws of GEORGIA as amended effective July 18, 1990, and as presently in effect. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 3.)
GULF
(d) 1 - Restated Articles of Incorporation of GULF and amendments thereto through November 8, 1993. (Designated in Registration No. 33-43739 as Exhibit 4(b)-1, in Form 8-K dated January 15, 1992, File No. 0-2429, as Exhibit 1(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(b)-2, in Form 8-K dated September 22, 1993, File No. 0-2429, as Exhibit 4 and in Form 8-K dated November 3, 1993, File No. 0-2429, as Exhibit 4.)
(d) 2 - By-laws of GULF as amended effective February 25, 1994, and as presently in effect. (Designated in GULF's Form 10-K for the year ended December 31, 1993, as Exhibit 3(d)2.)
MISSISSIPPI
(e) 1 - Articles of incorporation of MISSISSIPPI, articles of merger of Mississippi Power Company (a Maine corporation) into MISSISSIPPI and articles of amendment to the articles of incorporation of MISSISSIPPI through August 19, 1993. (Designated in Registration No. 2-71540 as Exhibit 4(a)-1, in Form U5S for 1987, File No. 30-222-2, as Exhibit B-10, in Registration No. 33-49320 as Exhibit 4(b)-(1), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibits 4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File No. 0-6849, as Exhibit 4(b)-3 and in Form 8-K dated August 18, 1993, File No. 0-6849, as Exhibit 4(b)-3.)
(e) 2 - By-laws of MISSISSIPPI as amended effective August 22, 1989, and as presently in effect. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1989, as Exhibit 3(b).)
SAVANNAH
(f) 1 - Charter of SAVANNAH and amendments thereto through November 10, 1993. (Designated in Registration Nos. 33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2) and in Form 8-K dated November 9, 1993, File No. 1-5072, as Exhibit 4(b).)
(f) 2 - By-laws of SAVANNAH as amended effective February 16, 1994, and as presently in effect. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1993, as Exhibit 3(f)2.)
(4) Instruments Describing Rights of Security Holders, Including Indentures
ALABAMA
(b) - Indenture dated as of January 1, 1942, between ALABAMA and Chemical Bank, as Trustee, and indentures supplemental thereto through that dated as of December 1, 1994. (Designated in Registration Nos. 2-59843 as Exhibit 2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit 2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2, 2-73727 as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083 as Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in ALABAMA's Form 10-K for the year ended December 31, 1990, File No. 1-3164, as Exhibit 4(c), in Registration Nos. 33-43917 as Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated January 20, 1993, File No. 1-3436, as Exhibit 4(a)-3, in Form 8-K dated February 17, 1993, File No. 1-3436, as Exhibit 4(a)-3, in Form 8-K dated March 10, 1993, File No. 1-3436, as Exhibit 4(a)-3, in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Form 8-K dated June 24, 1993, File No. 1-3436, as Exhibit 4, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Form 8-K dated November 16, 1993, File No. 1-3436, as Exhibit 4(b), in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Certificate of Notification, File No. 70-8069, as Exhibit A and in Form 8-K dated November 30, 1994, File No. 1-3436, as Exhibit 4.)
GEORGIA
(c) 1 - Indenture dated as of March 1, 1941, between GEORGIA and Chemical Bank, as Trustee, and indentures supplemental thereto dated as of March 1, 1941, March 3, 1941 (3 indentures), March 6, 1941 (139 indentures), March 1, 1946 (88 indentures) and December 1, 1947, through May 1, 1995. (Designated in Registration Nos. 2-4663 as Exhibits B-3 and B-3(a), 2-7299 as Exhibit 7(a)-2, 2-61116 as Exhibit 2(a)-3 and 2(a)-4, 2-62488 as Exhibit 2(a)-3, 2-63393 as Exhibit 2(a)-4, 2-63705 as Exhibit 2(a)-3, 2-68973 as Exhibit 2(a)-3, 2-70679 as Exhibit 4(a)-(2), 2-72324 as Exhibit 4(a)-2, 2-73987 as Exhibit 4(a)-(2), 2-77941 as Exhibits 4(a)-(2) and 4(a)-(3), 2-79336 as Exhibit 4(a)-(2), 2-81303 as Exhibit 4(a)-(2), 2-90105 as Exhibit 4(a)-(2), 33-5405 as Exhibit 4(a)-(2), 33-14367 as Exhibits 4(a)-(2) and 4(a)-(3), 33-22504 as Exhibits 4(a)-(2), 4(a)-(3) and 4(a)-(4), 33-32420 as Exhibit 4(a)-(2), 33-35683 as Exhibit 4(a)-(2), in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 4(a)(3), in Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibit 4(a)(5), in Registration No. 33-48895 as Exhibit 4(a)-(2), in Form 8-K dated August 26, 1992, File No. 1-6468, as Exhibit 4(a)-(3), in Form 8-K dated September 9, 1992, File No. 1-6468, as Exhibits 4(a)-(3) and 4(a)-(4), in Form 8-K dated September 23, 1992, File No. 1-6468, as Exhibit 4(a)-(3), in Form 8-A dated October 12, 1992, as Exhibit 2(b), in Form 8-K dated January 27, 1993, File No. 1-6468, as Exhibit 4(a)-(3), in Registration No. 33-49661 as Exhibit 4(a)-(2), in Form 8-K dated July 26, 1993, File No. 1-6468, as Exhibit 4, in Certificate of Notification, File No. 70-7832, as Exhibit M, in
Certificate of Notification, File No. 70-7832, as Exhibit C, in Certificate of Notification, File No. 70-7832, as Exhibits K and L, in Certificate of Notification, File No. 70-8443, as Exhibit C, in Certificate of Notification, File No. 70-8443, as Exhibit C, in Certificate of Notification, File No. 70-8443, as Exhibit E, in Certificate of Notification, File No. 70-8443, as Exhibit E, in Certificate of Notification, File No. 70-8443, as Exhibit E, in GEORGIA's Form 10-K for the year ended December 31, 1994, File No. 1-6468, as Exhibits 4(c)2 and 4(c)3, in Certificate of Notification, File No. 70-8443, as Exhibit C, in Certificate of Notification, File No. 70-8443, as Exhibit C and in Form 8-K dated May 17, 1995, File No. 1-6468, as Exhibit 4.)
* (c) 2 - Supplemental Indenture dated as of July 1, 1995, between GEORGIA and Chemical Bank, as Trustee.
* (c) 3 - Second Supplemental Indenture dated as of July 1, 1995, between GEORGIA and Chemical Bank, as Trustee.
* (c) 4 - Supplemental Indenture dated as of September 1, 1995, between GEORGIA and Chemical Bank, as Trustee.
* (c) 5 - Second Supplemental Indenture dated as of September 1, 1995, between GEORGIA and Chemical Bank, as Trustee.
* (c) 6 - Supplemental Indenture dated as of October 15, 1995, between GEORGIA and Chemical Bank, as Trustee.
(c) 7 - Indenture dated as of December 1, 1994, between GEORGIA and Trust Company Bank, as Trustee and indentures supplemental thereto through that dated as of December 15, 1994. (Designated in Certificate of Notification, File No. 70-8461, as Exhibits E and F.)
GULF
(d) - Indenture dated as of September 1, 1941, between GULF and The Chase Manhattan Bank (National Association), as Trustee, and indentures supplemental thereto through February 1, 1996. (Designated in Registration Nos. 2-4833 as Exhibit B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as Exhibit 2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2, 33-43739 as Exhibit 4(a)-2, in GULF's Form 10-K for the year ended December 31, 1991, File No. 0-2429, as Exhibit 4(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(a)-3, in Registration No. 33-50165 as Exhibit 4(a)-2, in Form 8-K dated July 12, 1993, File No. 0-2429, as Exhibit 4, in Certificate of Notification, File No. 70-8229, as Exhibit A, in Certificate of Notification, File No. 70-8229, as Exhibits E and F, in Form 8-K dated January 17, 1996, File No. 0-2429, as Exhibit 4 and in Certificate of Notification, File No. 70-8229, as Exhibit A.)
MISSISSIPPI
(e) - Indenture dated as of September 1, 1941, between MISSISSIPPI and Bankers Trust Company, as Successor Trustee, and indentures supplemental thereto through December 1, 1995. (Designated in Registration Nos. 2-4834 as Exhibit B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2, 2-71537 as Exhibit 4(a)-(2),
33-5414 as Exhibit 4(a)-(2), 33-39833 as Exhibit 4(a)-2, in MISSISSIPPI's Form 10-K for the year ended December 31, 1991, File No. 0-6849, as Exhibit 4(b), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibit 4(a)-2, in Second Certificate of Notification, File No. 70-7941, as Exhibit I, in MISSISSIPPI's Form 8-K dated February 26, 1993, File No. 0-6849, as Exhibit 4(a)-2, in Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated June 22, 1993, File No. 0-6849, as Exhibit 1, in Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated March 8, 1994, File No. 0-6849, as Exhibit 4, in Certificate of Notification, File No. 70-8127, as Exhibit C and in Form 8-K dated December 5, 1995, File No. 0-6849, as Exhibit 4.)
SAVANNAH
(f) - Indenture dated as of March 1, 1945, between SAVANNAH and Bank of New York, New York, as Trustee, and indentures supplemental thereto through May 1, 1995. (Designated in Registration Nos. 33-25183 as Exhibit 4(a)-(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit 4(a)-(2), in SAVANNAH's Form 10-K for the year ended December 31, 1991, File No. 1-5072, as Exhibit 4(b), in Form 8-K dated July 8, 1992, File No. 1-5072, as Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit 4(a)-(2), in Form 8-K dated July 22, 1993, File No. 1-5072, as Exhibit 4 and in Form 8-K dated May 18, 1995, File No. 1-5072, as Exhibit 4.)
(10) Material Contracts
SOUTHERN
(a) 1 - Service contracts dated as of January 1, 1984 and Amendment No. 1 dated as of September 6, 1985, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1984, File No. 1-3526, as Exhibit 10(a) and in SOUTHERN's Form 10-K for the year ended December 31, 1985, File No. 1-3526, as Exhibit 10(a)(3).)
(a) 2 - Service contract dated as of July 17, 1981, between SCS and SEI. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1985, File No. 1-3526, as Exhibit 10(a)(2).)
(a) 3 - Service contract dated as of March 3, 1988, between SCS and SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.)
(a) 4 - Service contract dated as of January 15, 1991, between SCS and Southern Nuclear. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1991, File No. 1-3526, as Exhibit 10(a)(4).)
(a) 5 - Service Contract dated as of December 12, 1994, between SCS and Mobile Energy Services Company, Inc. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)58.)
(a) 6 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(b).)
(a) 7 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, ALABAMA and GEORGIA. (Designated in Registration No. 2-59634 as Exhibit 5(c), in GEORGIA's Form 10-K for the year ended December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2) and in ALABAMA's Form 10-K for the year ended December 31, 1994, File No. 1-3164, as Exhibit 10(b)18.)
(a) 8 - Joint Committee Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. (Designated in Registration No. 2-61116 as Exhibit 5(d).)
(a) 9 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of January 6, 1975, between GEORGIA and OPC. (Designated in Form 8-K for January, 1975, File No. 1-6468, as Exhibit (b)(1).)
(a) 10 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between GEORGIA and OPC. (Designated in Form 8-K for January, 1975, File No. 1-6468, as Exhibit (b)(3).)
(a) 11 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between GEORGIA and OPC. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(g).)
(a) 12 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of March 26, 1976, between GEORGIA and OPC. (Designated in Certificate of Notification, File No. 70-5592, as Exhibit A.)
(a) 13 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between GEORGIA and OPC. (Designated in Certificate of Notification, File No. 70-5592, as Exhibit B.)
(a) 14 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(1).)
(a) 15 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. (Designated in Form 8-K for February 1977, File No. 1-6468, as Exhibit (b)(2).)
(a) 16 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-5792, as Exhibit B-1 and in Form 8-K for January 1977, File No. 1-6468, as Exhibit (B)(3).)
(a) 17 - Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-5792, as Exhibit B-2.)
(a) 18 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption Agreement dated as of November 16, 1983, between GEORGIA and MEAG. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1983, File No. 1-6468, as Exhibit 10(k)(4).)
(a) 19 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(2).)
(a) 20 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(4).)
(a) 21 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and Dalton. (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(8).)
(a) 22 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K for February 1977, File No. 1-6468, as Exhibit (b)(4).)
(a) 23 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of April 19, 1977, between GEORGIA and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(3).)
(a) 24 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between GEORGIA and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(7).)
(a) 25 - Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 30, 1985, Amendment No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of August 1, 1988 and Amendment No. 4 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-3, in SOUTHERN's Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(2), in SOUTHERN's Form 10-K for the year ended December 31, 1989, File No. 1-3526, as Exhibit 10(n)(2) and in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)54.)
(a) 26 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 3, 1985 and Amendment No. 2 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-4, in SOUTHERN's Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(4) and in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)55.)
(a) 27 - Plant Robert W. Scherer Purchase, Sale and Option Agreement dated as of May 15, 1980, between GEORGIA and MEAG. (Designated in Form U-1, File No. 70-6481, as Exhibit B-1.)
(a) 28 - Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between GEORGIA and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-2.)
(a) 29 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between GEORGIA and GULF. (Designated in Form U-1, File No. 70-6573, as Exhibit B-4, in SOUTHERN's Form 10-K for the year ended December 31, 1987, as Exhibit 10(o)(2) and in SOUTHERN's Form 10-K for the year ended December 31, 1989, as Exhibit 10(n)(2).)
(a) 30 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA and GULF. (Designated in Form U-1, File No. 70-6573, as Exhibit B-5.)
(a) 31 - Plant Robert W. Scherer Unit No. Four Amended and Restated Purchase and Ownership Participation Agreement by and among GEORGIA, FP&L and JEA, dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. (Designated in Form U-1, File No. 70-7843, as Exhibit B-1 and in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)60.)
(a) 32 - Plant Robert W. Scherer Unit No. Four Operating Agreement by and among GEORGIA, FP&L and JEA, dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. (Designated in Form U-1, File No. 70-7843, as Exhibit B-2 and in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)61.)
(a) 33 - Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18, 1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1981, File No. 0-6849, as Exhibit 10(c)(2) and in GEORGIA's Form 10-K for the year ended December 31, 1982, File No. 1-6468, as Exhibit 10(r)(3).)
(a) 34 - Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1 dated August 30, 1984 and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1982, File No. 1-6468, as Exhibit 10(s)(2), in SOUTHERN's Form 10-K for the year ended December 31, 1984, File No. 1-3526, as Exhibit 10(r)(2) and in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(s)(2).)
(a) 35 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(d).)
(a) 36 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(e).)
(a) 37 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(f).)
(a) 38 - Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(x).)
(a) 39 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in GULF's Form 10-K for the year ended December 31, 1991, File No. 0-2429, as Exhibit 10(1).)
(a) 40 - Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. (Designated in GULF's Form 10-K for the year ended December 31, 1991, File No. 0-2429, as Exhibit 10(m).)
(a) 41 - Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18, 1988, between OPC and GEORGIA. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1988, File No. 1-6468, as Exhibit 10(x).)
(a) 42 - Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between OPC and GEORGIA. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1988, File No. 1-6468, as Exhibit 10(y).)
(a) 43 - Purchase and Ownership Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-1.)
(a) 44 - Operating Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-2.)
(a) 45 - Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Gulf States and MISSISSIPPI. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1981, File No. 0-6849, as Exhibit 10(f), in MISSISSIPPI's Form 10-K for the year ended December 31, 1982, File No. 0-6849, as Exhibit 10(f)(2) and in MISSISSIPPI's Form 10-K for the year ended December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).)
(a) 46 - Form of commitment agreement, Amendment No. 1 and Amendment No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and MISSISSIPPI revolving credits. (Designated in Form U-1, File No. 70-7738, as Exhibit A-5 and in Form U-1, File No. 70-7937, as A-5(b).)
(a) 47 - Block Power Sale Agreement between GEORGIA and OPC dated as of November 12, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(cc).)
(a) 48 - Coordination Services Agreement between GEORGIA and OPC dated as of November 12, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(dd).)
(a) 49 - Amended and Restated Nuclear Managing Board Agreement for Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and Dalton dated as of July 1, 1993. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)49.)
(a) 50 - Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between GEORGIA and OPC dated as of November 12, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(ff).)
(a) 51 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and Dalton dated as of December 7, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(gg).)
(a) 52 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December 7, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(hh).)
(a) 53 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1992, File No. 1-3526, as Exhibit 10(a)53.)
(a) 54 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and JEA. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)56.)
(a) 55 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)57.)
(a) 56 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)58.)
(a) 57 - Power Purchase Agreement dated as of December 3, 1993 between GEORGIA and FPC. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)59.)
(a) 58 - Operating Agreement for the Joseph M. Farley Nuclear Plant between ALABAMA and Southern Nuclear dated as of December 23, 1991. (Designated in Form U-1, File No. 70-7530, as Exhibit B-7.)
(a) 59 - Nuclear Services Agreement between Southern Nuclear and GEORGIA dated as of October 31, 1991. (Designated in Form U-1, File No. 70-7530, as Exhibit B-6.)
(a) 60 - Nuclear Managing Board Agreement among GEORGIA, OPC, MEAG and Dalton dated as of November 12, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(ee).)
* (a) 61 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1995.
* (a) 62 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1995.
* (a) 63 - The Southern Company Employee Savings Plan, Amended and Restated effective July 3, 1995 and First Amendment and Second Amendment thereto.
* (a) 64 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective April 1, 1995 and First Amendment thereto.
(a) 65 - Pension Plan For Employees of ALABAMA, Amended and Restated effective as of January 1, 1989. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)69.)
(a) 66 - Pension Plan For Employees of GEORGIA, Amended and Restated effective as of January 1, 1989. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)70.)
(a) 67 - Pension Plan For Employees of SCS, Amended and Restated effective as of January 1, 1989. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)71.)
* (a) 68 - First Amendment to the Pension Plan for Employees of SCS, effective as of January 1, 1995.
(a) 69 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)72.)
* (a) 70 - First Amendment and Second Amendment to The Southern Company Performance Pay Plan.
* (a) 71 - Supplemental Benefit Plan for ALABAMA.
* (a) 72 - Supplemental Benefit Plan for GEORGIA.
* (a) 73 - Supplemental Benefit Plan for SCS and SEI.
(a) 74 - The Deferred Compensation Plan for the Directors of The Southern Company. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)76.)
* (a) 75 - First Amendment and Second Amendment to The Deferred Compensation Plan for the Directors of The Southern Company.
(a) 76 - The Southern Company Outside Directors Pension Plan. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)77.)
* (a) 77 - The Southern Company Deferred Compensation Plan.
(a) 78 - The Southern Company Outside Directors Stock Plan. (Designated in Registration No. 33-54415 as Exhibit 4(c).)
* (a) 79 - First Amendment to The Southern Company Outside Directors Stock Plan.
* (a) 80 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto.
(a) 81 - The Southern Company Executive Stock Plan for the Southern Electric System and the First Amendment thereto. (Designated in Registration No. 33-30171 as Exhibit 4(c).)
* (a) 82 - Second Amendment to The Southern Company Executive Stock Plan for the Southern Electric System.
ALABAMA
(b) 1 - Service contracts dated as of January 1, 1984 and Amendment No. 1 dated as of September 6, 1985, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN. See Exhibit 10(a)1 herein.
(b) 2 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)6 herein.
(b) 3 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.
(b) 4 - Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18, 1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.
(b) 5 - Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1, dated August 30, 1984 and Amendment No. 2, dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)34 herein.
(b) 6 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(b) 7 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(b) 8 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(b) 9 - Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)38 herein.
(b) 10 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(b) 11 - Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(b) 12 - Firm Power Purchase Contract between ALABAMA and AMEA. (Designated in Certificate of Notification, File No. 70-7212, as Exhibit B.)
(b) 13 - 1991 Firm Power Purchase Contract between ALABAMA and AMEA. (Designated in Form U-1, File No. 70-7873, as Exhibit B-1.)
(b) 14 - Purchase and Ownership Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. See Exhibit 10(a)43 herein.
(b) 15 - Operating Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. See Exhibit 10(a)44 herein.
(b) 16 - Form of commitment agreement, Amendment No. 1 and Amendment No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and MISSISSIPPI revolving credits. See Exhibit 10(a)46 herein.
(b) 17 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit 10(a)53 herein.
(b) 18 - Operating Agreement for the Joseph M. Farley Nuclear Plant between ALABAMA and Southern Nuclear dated as of December 23, 1991. See Exhibit 10(a)58 herein.
* (b) 19 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1995. See Exhibit 10(a)61 herein.
* (b) 20 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1995. See Exhibit 10(a)62 herein.
* (b) 21 - The Southern Company Employee Savings Plan, Amended and Restated effective July 3, 1995 and First Amendment and Second Amendment thereto. See Exhibit 10(a)63 herein.
* (b) 22 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective April 1, 1995 and First Amendment thereto. See Exhibit 10(a)64 herein.
(b) 23 - Pension Plan For Employees of ALABAMA, Amended and Restated effective as of January 1, 1989. See Exhibit 10(a)65 herein.
(b) 24 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)69 herein.
* (b) 25 - First Amendment and Second Amendment to The Southern Company Performance Pay Plan. See Exhibit 10(a)70 herein.
* (b) 26 - Supplemental Benefit Plan for ALABAMA. See Exhibit 10(a)71 herein.
* (b) 27 - The Southern Company Deferred Compensation Plan. See Exhibit 10(a)77 herein.
(b) 28 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)76 herein.
* (b) 29 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See Exhibit 10(a)80 herein.
GEORGIA
(c) 1 - Service contracts dated as of January 1, 1984 and Amendment No. 1 dated as of September 6, 1985, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN. See Exhibit 10(a)1 herein.
(c) 2 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)6 herein.
(c) 3 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.
(c) 4 - Joint Committee Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)8 herein.
(c) 5 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of January 6, 1975, between GEORGIA and OPC. See Exhibit 10(a)9 herein.
(c) 6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between GEORGIA and OPC. See Exhibit 10(a)10 herein.
(c) 7 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between GEORGIA and OPC. See Exhibit 10(a)11 herein.
(c) 8 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of March 26, 1976, between GEORGIA and OPC. See Exhibit 10(a)12 herein.
(c) 9 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between GEORGIA and OPC. See Exhibit 10(a)13 herein.
(c) 10 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. See Exhibit 10(a)14 herein.
(c) 11 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. See Exhibit 10(a)15 herein.
(c) 12 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)16 herein.
(c) 13 - Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)17 herein.
(c) 14 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption Agreement dated as of November 16, 1983, between GEORGIA and MEAG. See Exhibit 10(a)18 herein.
(c) 15 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)19 herein.
(c) 16 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)20 herein.
(c) 17 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and Dalton. See Exhibit 10(a)21 herein.
(c) 18 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)22 herein.
(c) 19 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of April 19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)23 herein.
(c) 20 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)24 herein.
(c) 21 - Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 30, 1985, Amendment No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of August 1, 1988 and Amendment No. 4 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)25 herein.
(c) 22 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 3, 1985 and Amendment No. 2 dated as of December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)26 herein.
(c) 23 - Plant Robert W. Scherer Purchase, Sale and Option Agreement dated as of May 15, 1980, between GEORGIA and MEAG. See Exhibit 10(a)27 herein.
(c) 24 - Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between GEORGIA and Dalton. See Exhibit 10(a)28 herein.
(c) 25 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between GEORGIA and GULF. See Exhibit 10(a)29 herein.
(c) 26 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA and GULF. See Exhibit 10(a)30 herein.
(c) 27 - Plant Robert W. Scherer Unit No. Four Amended and Restated Purchase and Ownership Participation Agreement by and among GEORGIA, FP&L and JEA dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)31 herein.
(c) 28 - Plant Robert W. Scherer Unit No. Four Operating Agreement by and among GEORGIA, FP&L and JEA dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)32 herein.
(c) 29 - Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18, 1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.
(c) 30 - Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1, dated August 30, 1984 and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)34 herein.
(c) 31 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(c) 32 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(c) 33 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(c) 34 - Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)38 herein.
(c) 35 - Power Purchase Agreement dated as of December 3, 1993 between GEORGIA and FPC. See Exhibit 10(a)57 herein.
(c) 36 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(c) 37 - Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(c) 38 - Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18, 1988, between OPC and GEORGIA. See Exhibit 10(a)41 herein.
(c) 39 - Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between OPC and GEORGIA. See Exhibit 10(a)42 herein.
(c) 40 - Form of commitment agreement, Amendment No. 1 and Amendment No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and MISSISSIPPI revolving credits. See Exhibit 10(a)46 herein.
(c) 41 - Block Power Sale Agreement between GEORGIA and OPC dated as of November 12, 1990. See Exhibit 10(a)47 herein.
(c) 42 - Coordination Services Agreement between GEORGIA and OPC dated as of November 12, 1990. See Exhibit 10(a)48 herein.
(c) 43 - Amended and Restated Nuclear Managing Board Agreement for Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and Dalton dated as of July 1, 1993. See Exhibit 10(a)49 herein.
(c) 44 - Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between GEORGIA and OPC dated as of November 12, 1990. See Exhibit 10(a)50 herein.
(c) 45 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and Dalton dated as of December 7, 1990. See Exhibit 10(a)51 herein.
(c) 46 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December 7, 1990. See Exhibit 10(a)52 herein.
(c) 47 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and JEA. See Exhibit 10(a)54 herein.
(c) 48 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)55 herein.
(c) 49 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)56 herein.
(c) 50 - Certificate of Limited Partnership of Georgia Power Capital. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit B.)
(c) 51 - Amended and Restated Agreement of Limited Partnership of Georgia Power Capital, dated as of December 1, 1994. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit C.)
(c) 52 - Action of General Partner of Georgia Power Capital creating the Series A Preferred Securities. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit D.)
(c) 53 - Guarantee Agreement of GEORGIA dated as of December 1, 1994, for the benefit of the holders from time to time of the Series A Preferred Securities. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit G.)
(c) 54 - Nuclear Services Agreement between Southern Nuclear and GEORGIA dated as of October 31, 1991. See Exhibit 10(a)59 herein.
(c) 55 - Nuclear Managing Board Agreement among GEORGIA, OPC, MEAG and Dalton dated as of November 12, 1990. See Exhibit 10(a)60 herein.
* (c) 56 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1995. See Exhibit 10(a)61 herein.
* (c) 57 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1995. See Exhibit 10(a)62 herein.
* (c) 58 - The Southern Company Employee Savings Plan, Amended and Restated effective July 3, 1995 and First Amendment and Second Amendment thereto. See Exhibit 10(a)63 herein.
* (c) 59 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective April 1, 1995 and First Amendment thereto. See Exhibit 10(a)64 herein.
(c) 60 - Pension Plan For Employees of GEORGIA, Amended and Restated effective as of January 1, 1989. See Exhibit 10(a)66 herein.
(c) 61 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)69 herein.
* (c) 62 - First Amendment and Second Amendment to The Southern Company Performance Pay Plan. See Exhibit 10(a)70 herein.
* (c) 63 - Supplemental Benefit Plan for GEORGIA. See Exhibit 10(a)72 herein.
* (c) 64 - The Southern Company Deferred Compensation Plan. See Exhibit 10(a)77 herein.
(c) 65 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)76 herein.
* (c) 66 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See Exhibit 10(a)80 herein.
GULF
(d) 1 - Service contracts dated as of January 1, 1984 and Amendment No. 1 dated as of September 6, 1985, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN. See Exhibit 10(a)1 herein.
(d) 2 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)6 herein.
(d) 3 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between GEORGIA and GULF. See Exhibit 10(a)29 herein.
(d) 4 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between GEORGIA and GULF. See Exhibit 10(a)30 herein.
(d) 5 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and JEA. See Exhibit 10(a)54 herein.
(d) 6 - Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18, 1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.
(d) 7 - Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1 dated August 30, 1984 and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)34 herein.
(d) 8 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(d) 9 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(d) 10 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(d) 11 - Agreement between GULF and AEC, effective August 1, 1985. (Designated in GULF's Form 10-K for the year ended December 31, 1985, File No. 0-2429, as Exhibit 10(g).)
(d) 12 - Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)38 herein.
(d) 13 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(d) 14 - Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)40 herein.
* (d) 15 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1995. See Exhibit 10(a)61 herein.
* (d) 16 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1995. See Exhibit 10(a)62 herein.
* (d) 17 - The Southern Company Employee Savings Plan, Amended and Restated effective July 3, 1995 and First Amendment and Second Amendment thereto. See Exhibit 10(a)63 herein.
* (d) 18 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective April 1, 1995 and First Amendment thereto. See Exhibit 10(a)64 herein.
(d) 19 - Pension Plan For Employees of GULF, Amended and Restated effective as of January 1, 1989. (Designated in GULF's Form 10-K for the year ended December 31, 1994, File No. 0-2429, as Exhibit 10(d)18.)
(d) 20 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)69 herein.
* (d) 21 - First Amendment and Second Amendment to The Southern Company Performance Pay Plan. See Exhibit 10(a)70 herein.
* (d) 22 - Supplemental Benefit Plan for GULF.
* (d) 23 - The Southern Company Deferred Compensation Plan. See Exhibit 10(a)77 herein.
(d) 24 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)76 herein.
* (d) 25 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See Exhibit 10(a)80 herein.
MISSISSIPPI
(e) 1 - Service contracts dated as of January 1, 1984 and Amendment No. 1 dated September 6, 1985, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN. See Exhibit 10(a)1 herein.
(e) 2 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)6 herein.
(e) 3 - Amended and Restated Unit Power Sales Agreement dated February 18, 1982 and Amendment No. 1 dated May 18, 1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.
(e) 4 - Amended and Restated Unit Power Sales Agreement dated May 19, 1982, Amendment No. 1 dated August 30, 1984, and Amendment No. 2 dated October 30, 1987, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit 10(a)34 herein.
(e) 5 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(e) 6 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(e) 7 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(e) 8 - Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)38 herein.
(e) 9 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(e) 10 - Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(e) 11 - Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Gulf States and MISSISSIPPI. See Exhibit 10(a)45 herein.
(e) 12 - Form of commitment agreement, Amendment No. 1 and Amendment No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and MISSISSIPPI revolving credits. See Exhibit 10(a)46 herein.
(e) 13 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA MISSISSIPPI and SCS. See Exhibit 10(a)53 herein.
* (e) 14 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1995. See Exhibit 10(a)61 herein.
* (e) 15 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1995. See Exhibit 10(a)62 herein.
* (e) 16 - The Southern Company Employee Savings Plan, Amended and Restated effective July 3, 1995 and First Amendment and Second Amendment thereto. See Exhibit 10(a)63 herein.
* (e) 17 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective April 1, 1995 and First Amendment thereto. See Exhibit 10(a)64 herein.
(e) 18 - Pension Plan For Employees of MISSISSIPPI, Amended and Restated effective as of January 1, 1989. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1994, File No. 0-6849, as Exhibit 10(e)18.)
(e) 19 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)69 herein.
* (e) 20 - First Amendment and Second Amendment to The Southern Company Performance Pay Plan. See Exhibit 10(a)70 herein.
* (e) 21 - Supplemental Benefit Plan for MISSISSIPPI.
* (e) 22 - The Southern Company Deferred Compensation Plan. See Exhibit 10(a)77 herein.
(e) 23 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)76 herein.
* (e) 24 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See Exhibit 10(a)80 herein.
SAVANNAH
(f) 1 - Service contract dated as of March 3, 1988, between SCS and SAVANNAH. See Exhibit 10(a)3 herein.
(f) 2 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)6 herein.
(f) 3 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(f) 4 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(f) 5 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(f) 6 - Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)38 herein.
(f) 7 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(f) 8 - Transition Energy Agreement dated December 31, 1990, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(f) 9 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)55 herein.
(f) 10 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated December 15, 1992. See Exhibit 10(a)56 herein.
* (f) 11 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1995. See Exhibit 10(a)61 herein.
* (f) 12 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1995. See Exhibit 10(a)62 herein.
* (f) 13 - The Southern Company Employee Savings Plan, Amended and Restated effective July 3, 1995 and First Amendment and Second Amendment thereto. See Exhibit 10(a)63 herein.
* (f) 14 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective April 1, 1995 and First Amendment thereto. See Exhibit 10(a)64 herein.
(f) 15 - Employees' Retirement Plan of SAVANNAH, Amended and Restated effective January 1, 1989. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1994, File No. 1-5072, as Exhibit 10(f)15.)
* (f) 16 - First Amendment to the Employees' Retirement Plan of SAVANNAH.
* (f) 17 - Supplemental Executive Retirement Plan of SAVANNAH, Amended and Restated effective January 1, 1996.
(f) 18 - Deferred Compensation Plan for Key Employees of SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1994, File No. 1-5072, as Exhibit 10(f)17.)
* (f) 19 - First Amendment to the Deferred Compensation Plan for Key Employees of SAVANNAH.
(f) 20 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)69 herein.
* (f) 21 - First Amendment and Second Amendment to The Southern Company Performance Pay Plan. See Exhibit 10(a)70 herein.
(f) 22 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)76 herein.
(f) 23 - Deferred Compensation Plan for Directors of SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year ended December 31, 1994, File No. 1-5072, as Exhibit 10(f)20.)
* (f) 24 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See Exhibit 10(a)80 herein.
(21) *Subsidiaries of Registrants - Contained herein at page IV-5.
(23) Consents of Experts and Counsel
SOUTHERN
* (a) - The consent of Arthur Andersen LLP is contained herein at page IV-6.
ALABAMA
* (b) - The consent of Arthur Andersen LLP is contained herein at page IV-7.
GEORGIA
* (c) - The consent of Arthur Andersen LLP is contained herein at page IV-8.
GULF
* (d) - The consent of Arthur Andersen LLP is contained herein at page IV-9.
MISSISSIPPI
* (e) - The consent of Arthur Andersen LLP is contained herein at page IV-10.
SAVANNAH
* (f) - The consent of Arthur Andersen LLP is contained herein at page IV-11.
(24) Powers of Attorney and Resolutions
SOUTHERN
* (a) - Power of Attorney and resolution.
ALABAMA
* (b) - Power of Attorney and resolution.
GEORGIA
* (c) - Power of Attorney and resolution.
GULF
* (d) - Power of Attorney and resolution.
MISSISSIPPI
* (e) - Power of Attorney and resolution.
SAVANNAH
* (f) - Power of Attorney and resolution.
(27) Financial Data Schedule
SOUTHERN
(a) - Financial Data Schedule. (Designated in Form 8-K dated February 21, 1996, File No. 1-3526, as Exhibit 27.)
ALABAMA
(b) - Financial Data Schedule. (Designated in Form 8-K dated February 21, 1996, File No. 1-3164, as Exhibit 27.)
GEORGIA
(c) - Financial Data Schedule. (Designated in Form 8-K dated February 21, 1996, File No. 1-6468, as Exhibit 27.)
GULF
(d) - Financial Data Schedule. (Designated in Form 8-K dated February 21, 1996, File No. 0-2429, as Exhibit 27.)
MISSISSIPPI
(e) - Financial Data Schedule. (Designated in Form 8-K dated February 21, 1996, File No. 0-6849, as Exhibit 27.)
SAVANNAH
(f) - Financial Data Schedule. (Designated in Form 8-K dated February 21, 1996, File No. 1-5072, as Exhibit 27.)