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), SDIG and various other subsidiaries related to foreign operations and domestic non-utility operations (see Exhibit 21 herein). At this time, the operations of the other subsidiaries are not material. SEI designs, builds, owns and operates power production 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. Communications, beginning in mid-1995, will provide digital wireless communications services -- over the 800-megahertz frequency band -- to SOUTHERN's subsidiaries and also will market these services to the public within the Southeast. Southern Nuclear provides services to the Southern electric system's nuclear plants. SDIG develops new business opportunities related to energy products and services.
SEGCO owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000 volt transmission lines extending from Plant Gaston to the Georgia state line at which point connection is made with the GEORGIA transmission line system.
The SOUTHERN System
The transmission facilities of each of the operating affiliates and SEGCO are connected to the respective company's own generating plants and other sources of power and are interconnected with the transmission facilities of the other operating affiliates and SEGCO by means of heavy-duty high voltage lines. (In the case of GEORGIA's integrated transmission system, see Item 1 - BUSINESS - "Territory Served" herein.)
Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases
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and sales, transfers of economy energy and other similar transactions. Additionally, the operating affiliates have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Carolina Power & Light Company, Duke 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, SDIG 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 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 existing subsidiaries.
SEI's primary business focus is international and domestic cogeneration, the independent power market, and the privatization and development of generation facilities in the international market. SEI currently operates three domestic independent power production projects totaling 280 megawatts and is one-third owner of one of these (which produces 180 megawatts). SEI (through subsidiaries) has a contract to sell electric energy to Virginia Electric and Power Company from a facility it is constructing in King George, Virginia. Upon completion, currently planned for 1996, SEI will operate the 220 megawatt coal-fired plant. SOUTHERN owns 50% of the project.
In April 1993, SOUTHERN completed the purchase of a 50% interest in Freeport, an electric utility on the Island of Grand Bahama, for a purchase price of $35.5 million. Freeport has generating capacity of about 112 megawatts. In August 1993, SOUTHERN completed the purchase of a 55% interest in Alicura, an entity that owns the right to use the generation from a 1,000 megawatt hydroelectric generating facility in Argentina, for a net purchase price of approximately $188 million. In 1993, SOUTHERN completed the purchase of a 38% interest in Edelnor for the purchase price of $73 million. In December 1994, SOUTHERN purchased an additional 27% interest in Edelnor for $80 million. Edelnor is a utility located in Northern Chile that owns and operates a transmission grid and 96 megawatts of generating facilities and is building an additional 150 megawatt facility.
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Also in December 1994, SOUTHERN completed the acquisition of a 39% interest in a partnership that acquired the generation operations of the T&TEC, comprising approximately 1,178 megawatts of generating capacity for a purchase price of $85.6 million. Additionally, SOUTHERN purchased a 100% interest in an energy and recovery complex from Scott Paper Company for a purchase price of $350 million, which included the assumption of $85 million of outstanding tax-exempt debt. This complex is used to generate substantially all of the steam and electricity requirements of Scott's integrated pulp and paper mill located in Mobile, Alabama and has a generating capacity of 105 megawatts. Most of the facility's fuel needs are met from waste and by-products generated by Scott's pulping and woodlands operations.
SEI and SDIG render consulting services and market SOUTHERN system expertise in the United States and throughout the world. They contract with other public utilities, commercial concerns and government agencies for the rendition of services and the licensing of intellectual property. In addition, SDIG engages in energy management-related services and activities.
At year-end, the SEC authorized SOUTHERN to form a new subsidiary, Communications, and to invest up to $179 million in Communications. Communications has contracted with a prime vendor for the installation and construction of a wireless communications system in order to provide services to the general public, including SOUTHERN subsidiaries. The technology selected is new and still under development. Communications will be subject to both market and technology risks. It is anticipated that the operations of Communications, at least in its early years, will negatively affect earnings and cash flow. Furthermore, there can be no assurance that Communications will ultimately recover the cost of constructing its wireless communications system.
These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of rate-regulated operations. However, these activities also involve a higher degree of risk. SOUTHERN expects to make substantial investments over the period 1995-1997 in these and other new businesses.
Certain Factors Affecting the Industry
Various factors are currently affecting the electric utility industry in general, including increasing competition, costs required to comply with environmental regulations, and the potential for new business opportunities (with their associated risks) outside of traditional rate-regulated operations. The effects of these and other factors on the SOUTHERN system are described herein; particular reference is made to Item 1 - BUSINESS - "New Business Development,"- - "Competition" and -- "Environmental Regulation".
Construction Programs
The subsidiary companies of SOUTHERN are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Construction additions or acquisitions of property during 1995 through 1997 by the operating affiliates, SEGCO, SCS and Southern Nuclear are estimated as follows: (in millions)
=========================================================== 1995 1996 1997 ---------------------------- ALABAMA $ 604 $ 500 $ 502 GEORGIA 579 626 724 GULF 62 76 84 MISSISSIPPI 78 73 72 SAVANNAH 34 27 26 SEGCO 10 11 11 SCS 26 19 14 Southern Nuclear 2 2 1 ---------------------------------------------------------- SOUTHERN system* $1,395 $1,267 $1,362 ==========================================================
*System totals for years 1996 and 1997 are less than the sum of the subsidiaries due to changes made in GEORGIA's construction budget subsequent to approval of the SOUTHERN system construction budget. However, GEORGIA's management has adopted an initiative to reduce its 1996 and 1997 construction expenditures by approximately 10% from currently estimated amounts. There can be no assurance that such reductions will be achieved.
Reference is made to Note 4 to the financial statements of each registrant in Item 8 herein for the amounts of AFUDC included in the above estimates. The construction estimates do not include amounts which may be spent by Communications or SEI (or the subsidiary(s) created to effect such project(s)) on future power production projects or the projects discussed earlier under "New Business Development." (See also Item 1 - BUSINESS - "Financing Programs" herein.) I-3
Estimated construction costs in 1995 are expected to be apportioned approximately as follows: (in millions)
*SCS and Southern Nuclear plan capital additions to general plant in 1995 of $26 million and $2 million, respectively, while SEGCO plans capital additions of $10 million to generating facilities.
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 cost of labor, equipment and materials; and cost of capital. Also, the SOUTHERN system construction estimates do not reflect expenditures by Communications or the possibility of SEI securing a contract(s) to buy or build additional generating facilities.
The operating affiliates do not have any baseload generating plants under construction. However, within the service area, the construction of combustion turbine peaking units with an aggregate capacity of approximately 1,100 megawatts is planned to be completed by 1997. In addition, significant construction will continue related to transmission and distribution facilities and the upgrading and extension of the useful lives of generating plants.
During 1991, the Georgia legislature passed legislation which requires GEORGIA and SAVANNAH each to file an Integrated Resource Plan for approval by the Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the construction of new power plants. (See Item 1 - BUSINESS - "Rate Matters -Integrated Resource Planning" herein.)
See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein for information with respect to certain existing and proposed environmental requirements and Item 2
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1994, operated 33 hydroelectric generating stations, 31 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 ------------------------------------------------------------ (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 (1) Gaston Unit 5 Wilsonville, AL 880,000 Miller Birmingham, AL 2,532,288 (2) --------- 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 886,303 (3) Wansley Carrollton, GA 925,550 (4) Yates Newnan, GA 1,250,000 --------- GEORGIA Total 9,676,553 ---------
Crist Pensacola, FL 1,045,000 Lansing Smith Panama City, FL 305,000 Scholz Chattahoochee, FL 80,000 Daniel Pascagoula, MS 500,000 (5) Scherer Unit 3 Macon, GA 204,500 (3) --------- 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 (5) Greene County Demopolis, AL 200,000 (1) --------- 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 (6) ---------- Total Fossil Steam 21,835,622 ----------
Nuclear Steam Farley Dothan, AL (ALABAMA) 1,720,000 ---------- Hatch Baxley, GA 816,630 (7) Vogtle Augusta, GA 1,060,240 (8) ---------- GEORGIA Total 1,876,870 ---------- Total Nuclear Steam 3,596,870 ----------
Combustion Turbines Arkwright Macon, GA 30,580 Atkinson Atlanta, GA 78,720 Bowen Cartersville, GA 39,400 McDonough Atlanta, GA 78,800 McIntosh Units 3, 4, 7, 8 Effingham County, GA 320,000 McManus Brunswick, GA 481,700 Mitchell Albany, GA 118,200 Wilson Augusta, GA 354,100 Wansley Carrollton, GA 26,322 (4) ---------- GEORGIA Total 1,527,822 ----------
Lansing Smith Unit A (GULF) Panama City, FL 39,400 ----------
Chevron Cogenerating Station Pascagoula, MS 147,292 (9) 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 (6) ---------- Total Combustion Turbines 2,054,054 ----------
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 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 (10) ---------- GEORGIA Total 862,480 ----------
Total Hydroelectric Facilities 2,445,205 ---------- Total Generating Capacity 29,931,751 ========== ============================================================
Notes: (1) Owned by ALABAMA and MISSISSIPPI as tenants in common in the proportions of 60% and 40%, respectively. (2) Excludes the capacity owned by AEC. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) (3) Capacity shown is GEORGIA's or GULF's (Unit 3 only) current portion: 8.4% of Units 1 and 2, 75% (25% for GULF) for Unit 3 and 16.55% for Unit 4 of total plant capacity. See Item 2 - PROPERTIES - "Proposed Sale of Property" and "Jointly-Owned Facilities" herein. (4) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity. (5) Represents 50% of the plant which is owned as tenants in common by GULF and MISSISSIPPI. (6) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS herein.) (7) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity. (8) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity. (9) Generation is dedicated to a single industrial customer. (10) Includes 5,400 megawatts of capacity for the Flint River Project damaged by flooding. See Item 1 - BUSINESS - "Regulation - Federal Power Act" herein.
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 25,936,900 kilowatts and occurred in July 1993. This amount excludes demand served by generation retained by MEAG and Dalton and excludes demand associated with power purchased from OPC and SEPA by its preference customers. At that time, 27,342,700 kilowatts were supplied by SOUTHERN system generation and 1,405,800 kilowatts (net) were sold to other parties through net purchased and interchanged power.
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The reserve margin for the Southern electric system at that time was 13.2%. The SOUTHERN system's maximum demand for 1994 of 24,545,700 kilowatts occurred in August. For information on the other registrant's peak demands, reference is made to Item 6 - SELECTED FINANCIAL DATA herein.
ALABAMA and GEORGIA will incur significant costs in decommissioning their nuclear units at the end of their useful lives. (See Item 1 - BUSINESS - "Regulations - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and GEORGIA's financial statements in Item 8 herein.)
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Other Electric Generation Facilities
Through special purpose subsidiaries, SOUTHERN owns interests in or operates independent power production facilities and foreign utility companies. For further discussion of other SEI projects, see Item 1 - BUSINESS - "New Business Development" herein. The generating capacity of these utilities (or facilities) at December 31, 1994, was as follows:
Notes: (1) Represents megawatts of capacity under a concession agreement expiring in the year 2023. (2) Cogeneration facility.
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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. See "Proposed Sale of Property" below for a description of the proposed sale of GEORGIA's remaining unsold ownership interest in Plant Scherer Unit 4.
In connection with the joint ownership arrangements for Plant Vogtle, GEORGIA has remaining commitments to purchase declining fractions of OPC's and MEAG's capacity and energy until 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 in the Statements of Income in Item 8 herein.
In December 1988, GEORGIA and OPC completed a joint ownership agreement for the Rocky Mountain project under which GEORGIA will retain its present investment in the project and OPC will finance, complete and operate the facility. Upon completion (scheduled for 1995), GEORGIA will own an undivided interest in the project equal to the proportion its investment bears to the total investment in the project (excluding each party's cost of funds and ad valorem taxes). For purposes of the ownership formula, GEORGIA's investment will be expressed in nominal dollars and OPC's investment will be expressed in constant 1987 dollars. Based on current cost estimates, GEORGIA's final ownership is estimated at approximately 25% of the project at completion.
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 in early 1996, and will be constructed, operated, and maintained by FPC. GEORGIA will have a one-third interest in the 150-megawatt unit, with retention 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.
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Proposed Sale of Property
GEORGIA has completed three of four separate transactions to sell Unit 4 of Plant Scherer to FP&L and JEA for a total price of approximately $808 million, including any gains on these transactions. FP&L would eventually own approximately 76.4% of this unit, with JEA owning the remainder. GEORGIA will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
======================================================== Percentage Closing of Sales Date Capacity Ownership Price -------------------------------------------------------- (Megawatts) (in millions) July 1991 290 35.46% $291 June 1993 258 31.44 253 June 1994 135 16.55 133 June 1995 135 16.55 131 -------------------------------------------------------- Total 818 100.00% $808 ========================================================
Plant Scherer, a jointly owned coal-fired generating plant, has four units with a total capacity of 3,272 megawatts. Unit 4 was completed in 1989.
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, 1990, to December 31, 1994, the operating affiliates, SEGCO, and others (i.e. SCS, Southern Nuclear and, beginning in 1993, various of the special purpose subsidiaries) recorded gross property additions and retirements as follows:
============================================================ Gross Property Additions Retirements -------------- ----------- (in millions) ALABAMA (1) $2,182 $ 336 GEORGIA (2) 2,928 2,030 GULF 349 118 MISSISSIPPI 415 69 SAVANNAH 173 15 SEGCO 81 12 Other (3) 262 87 ------------------------------------------------------------ SOUTHERN system $6,390 $2,667 ============================================================
(1) Includes approximately $62 million attributable to property sold to AEC in 1992. (2) Includes approximately $612 million attributable to property sold to OPC, FP&L and JEA, but excludes $231 million from the write-off of certain Plant Vogtle costs in 1990. (3) Net of intercompany eliminations.
Item 3.
Item 3. LEGAL PROCEEDINGS
(1) Stepak v. certain SOUTHERN officials (U.S. District Court for the Southern District of Georgia)
In April 1991, two SOUTHERN stockholders filed a derivative action suit against certain current and former directors and officers of SOUTHERN. The suit alleges violations of 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
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foregoing acts. The complaint seeks damages, including treble damages pursuant to RICO, in an unspecified amount, which if awarded, would be payable to SOUTHERN. The plaintiffs' amended complaint was dismissed by the court in March 1992. The court ruled the plaintiffs had failed to present adequately their allegation that the SOUTHERN board of directors' refusal of an earlier demand by the plaintiffs was wrongful. In April 1994, the U. S. Court of Appeals for the Eleventh 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. This action is still pending.
(2) Johnson v. ALABAMA (Circuit Court of Shelby County, Alabama)
In September 1990, two customers of ALABAMA filed a civil complaint in the Circuit Court of Shelby County, Alabama, against ALABAMA seeking to represent all persons who, prior to June 23, 1989, entered into agreements with ALABAMA for the financing of heat pumps and other merchandise purchased from vendors other than ALABAMA. The plaintiffs contended that ALABAMA was required to obtain a license under the Alabama Consumer Finance Act to engage in the business of making consumer loans. The plaintiffs were seeking an order declaring these agreements null and void and requiring ALABAMA to refund all payments, principal and interest, made under these agreements. The aggregate amount under these agreements, together with interest paid, currently is estimated to be $40 million.
In June 1993, the court ordered ALABAMA to refund or forfeit interest of approximately $10 million because of ALABAMA's failure to obtain such license. However, the court's order did not require any refund or forfeiture with respect to any principal payments under the agreements at issue. ALABAMA has appealed the court's order to the Supreme Court of Alabama.
The final outcome of this matter cannot be determined; however, in management's opinion, the final outcome will not have a material adverse effect on SOUTHERN's or ALABAMA's financial statements.
(3) In January 1995, GEORGIA 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. While GEORGIA 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 may be ultimately responsible.
The final outcome of this matter cannot now be determined; however, in management's opinion, based on the nature and extent of GEORGIA's activities relating to the site, the final outcome will not have a material adverse effect on SOUTHERN's or GEORGIA's financial statements.
(4) 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 $28 million and $32 million, respectively. The tax deficiency relates to a timing issue as to when taxes are paid; therefore, only the interest portion could affect future income. Management believes that the IRS position is incorrect, and GEORGIA has filed a petition with the U. S. Tax Court challenging the IRS 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.
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The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material adverse effect on SOUTHERN's or GEORGIA's financial statements.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation - Federal Power Act" and "Rate Matters" for a description of certain other administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, SEI, SCS, Southern Nuclear, SDIG 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. In management's opinion these various actions will not have a material adverse effect on any of the registrants' financial statements.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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EXECUTIVE OFFICERS OF SOUTHERN
(Inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3)
A. W. Dahlberg Chairman, President and Chief Executive Officer Age 54 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 46 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 50 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 55 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 46 Elected in 1995; President and Chief Executive Officer of MISSISSIPPI since 1991. 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 and Chief Financial Officer Age 55 Elected in 1986; responsible primarily for all aspects of financing for SOUTHERN. He has served as Executive Vice President of SCS since 1986.
Bill M. Guthrie Vice President Age 61 Elected in 1991; serves as Chief Production Officer for the SOUTHERN system. Senior Executive Vice President of SCS effective January 1994. He has also served as Executive Vice President of ALABAMA since 1988.
Each of the above is currently an officer of SOUTHERN, serving a term running from the last annual meeting of the directors (May 25, 1994) 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 $22 $18-1/2 Second Quarter 20-1/2 17-3/4 Third Quarter 20 17 Fourth Quarter 21 18-1/4
First Quarter $21-3/8 $18-3/8 Second Quarter 22-1/2 19-3/8 Third Quarter 23 20-1/2 Fourth Quarter 23-5/8 20-3/4 ---------------------------------------------------
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 28, 1995, the closing price of SOUTHERN's common stock was $20-5/8.
(b) Number of SOUTHERN's common stockholders at December 31, 1994: 234,927
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 1994 1993 ----------------------------------------------------
SOUTHERN First $191,262 $180,381 Second 191,262 180,948 Third 191,475 181,892 Fourth 192,758 182,351
ALABAMA First 66,500 62,900 Second 67,000 63,100 Third 66,900 63,400 Fourth 67,600 63,500
GEORGIA First 106,600 100,100 Second 107,200 100,400 Third 107,200 100,800 Fourth 108,300 101,100
GULF First 10,900 10,400 Second 11,000 10,400 Third 11,000 10,500 Fourth 11,100 10,500
MISSISSIPPI First 8,500 7,200 Second 8,500 7,200 Third 8,500 7,300 Fourth 8,600 7,300
SAVANNAH First 4,100 4,500 Second 4,100 5,500 Third 4,100 5,500 Fourth 4,000 5,500 -----------------------------------------------------
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.
II-1
The dividend paid per share by SOUTHERN was 28.5(cent) for each quarter of 1993 and 29.5(cent) for each quarter of 1994. The dividend paid on SOUTHERN's common stock for the first quarter of 1995 was raised to 30.5(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, 1994, were as follows:
======================================================== Retained Restricted Earnings Amount ---------- ----------- (in millions) ALABAMA $1,085 $ 807 GEORGIA 1,413 742 GULF 169 101 MISSISSIPPI 144 94 SAVANNAH 99 57 Consolidated 3,191 1,805 --------------------------------------------------------
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-38 through II-49.
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-127 through II-141.
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-247 through II-260.
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-53 through II-59.
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-145 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 1994 FINANCIAL STATEMENTS
II-3
II-4
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT The Southern Company and Subsidiary Companies 1994 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 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 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. As discussed in Note 4 to the financial statements, an uncertainty exists with respect to the actions of regulators regarding recoverability of the investment in the Rocky Mountain pumped storage hydroelectric project. The outcome of this uncertainty cannot be determined until a regulatory review is completed. Accordingly, no provision for any write-down of the costs associated with the Rocky Mountain project resulting from the potential actions of the Georgia Public Service Commission has been made in the accompanying financial statements.
/s/ A. W. Dahlberg A. W. Dahlberg Chairman, President, and Chief Executive Officer
/s/ W. L. Westbrook W. L. Westbrook Financial Vice President and Chief Financial Officer
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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, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-16 through II-37) referred to above present fairly, in all material respects, the financial position of The Southern Company and subsidiary companies as of December 31, 1994 and 1993, and the results of their operations and their cash flows for the periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 9 to the financial statements, effective January 1, 1993, The Southern Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an uncertainty exists with respect to the actions of the regulators regarding recoverability of the investment in the Rocky Mountain pumped storage hydroelectric project. The outcome of this uncertainty cannot be determined until a regulatory review is completed. Accordingly, no provision for any write-down of the costs associated with the Rocky Mountain project resulting from the potential actions of the Georgia Public Service Commission has been made in the accompanying financial statements.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 15, 1995
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The Southern Company and Subsidiary Companies 1994 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
The Southern Company's 1994 earnings were $989 million or $1.52 per share, a decrease of $13 million or 5 cents per share from the year 1993. Earnings were significantly affected in 1994 by efforts related to the company's strategy to remain a low-cost producer of electricity and a high-quality investment. These efforts included work force reduction programs in 1994 and additional investments in companies related to the core business of electricity. These investments have put downward pressure on earnings and return on equity, and that trend will continue in the near term. However, the investments should support growth and strength in the financial condition of the company as it emerges into a more competitive and global environment.
Costs related to the work force reduction programs decreased earnings by $61 million or 9 cents per share. These costs should be recovered through future savings in about two years. Additional non-operating or non-recurring items affected earnings in 1994 and 1993. After excluding these items in both years, 1994 earnings from operations of the ongoing business of selling electricity were $1.0 billion -- or $1.58 per share -- an increase of $11 million compared with 1993. The non-operating items that affected earnings were as follows:
Consolidated Earnings Net Income Per Share ----------------- ----------------- 1994 1993 1994 1993 ----------------- ----------------- (in millions)
Earnings as reported $ 989 $1,002 $1.52 $1.57 ----------------------------------------------------------------- Work force reduction programs in 1994 61 - .09 - Sale of facilities (28) (18) (.04) (.03) Environmental cleanup 5 25 .01 .04 Transportation fleet reduction - 13 - .02 Gulf States related - (6) - (.01) ----------------------------------------------------------------- Total non-operating 38 14 .06 .02 ----------------------------------------------------------------- Earnings from operations $1,027 $1,016 $1.58 $1.59 ================================================================= Amount and percent change $11 1.1% $(0.01) (0.6)% -----------------------------------------------------------------
In 1994, non-operating items -- both positive and negative -- had an impact on earnings, which resulted in a net reduction of $38 million. These items were: (1) Costs associated with work force reduction programs implemented in 1994 decreased earnings. (2) The third in a series of four separate transactions to sell Plant Scherer Unit 4 to two Florida utilities and the sale of a 50 percent interest in a cogeneration facility in Virginia increased earnings. (3) Environmental cleanup costs decreased earnings.
Items not discussed above that affected 1993 earnings were: (1) Costs associated with a transportation fleet reduction program decreased earnings. (2) Transactions related to a 1991 settlement agreement with Gulf States Utilities Company increased earnings.
In January 1994, The Southern Company board of directors approved a two-for-one common stock split in the form of a stock distribution. All common stock data reported reflect the stock distribution. Dividends paid on common stock during 1994 were $1.18 per share or 29 1/2 cents per quarter. During 1993 and 1992, dividends paid per share were $1.14 and $1.10, respectively. In January 1995, The Southern Company board of directors raised the quarterly dividend to 30 1/2 cents per share or an annual rate of $1.22 per share.
Revenues
Operating revenues decreased in 1994 and increased in 1993 and 1992 as a result of the following factors:
Increase (Decrease) From Prior Year ---------------------------- 1994 1993 1992 ---------------------------- (in millions) Retail -- Change in base rates $ 3 $ 3 $ 137 Sales growth 153 104 138 Weather (177) 198 (113) Fuel recovery and other (107) 199 (55) --------------------------------------------------------------- Total retail (128) 504 107 --------------------------------------------------------------- Sales for resale -- Within service area (87) 38 (8) Outside service area (108) (184) (87) --------------------------------------------------------------- Total sales for resale (195) (146) (95) Other operating revenues 131 58 11 --------------------------------------------------------------- Total operating revenues $(192) $416 $ 23 ============================================================== Percent change (2.3)% 5.2% 0.3% --------------------------------------------------------------
Retail revenues of $7.1 billion in 1994 decreased 1.8 percent from last year, compared with an increase of 7.4 percent in 1993. Under fuel cost recovery
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
provisions, fuel revenues generally equal fuel expense -- including the fuel component of purchased energy -- and do not affect net income.
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. Sales for resale revenues within the service area were $447 million in 1993, up 9.2 percent from the prior year. This increase resulted primarily from the prolonged hot summer weather, which increased the demand for electricity.
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components were as follows:
1994 1993 1992 -------------------------------- (in millions) Capacity $276 $350 $457 Energy 176 230 330 ----------------------------------------------------- Total $452 $580 $787 =====================================================
Capacity revenues decreased in 1994 and 1993 because the amount of capacity under contract declined by some 400 megawatts and 500 megawatts, respectively. In 1995, the contracted capacity will decline another 100 megawatts. 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 1994 and the percent change by year were as follows:
(billions of Amount Percent Change kilowatt-hours) ------ ------------------------ 1994 1994 1993 1992 ---- ------------------------ Residential 35.8 (2.6)% 9.5% 0.0% Commercial 34.1 3.8 5.9 2.1 Industrial 50.3 3.2 1.9 3.8 Other 0.9 3.8 4.6 (4.8) ----- Total retail 121.1 1.6 5.3 2.1 Sales for resale -- Within service area 8.1 (38.5) 9.5 (1.7) Outside service area 10.8 (13.5) (25.2) (16.2) ----- Total 140.0 (3.4) 2.1 (0.7) =================================================================
The rate of increase in 1994 retail energy sales was suppressed by the impact of weather. Residential energy sales registered the first annual decrease in more than a decade as a result of milder-than-normal summer weather in 1994, compared with the extremely hot summer of 1993. 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 1995 through 2005.
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 continue to decrease, primarily as a result of the scheduled decline in megawatts of capacity under contract.
Expenses
Total operating expenses of $6.6 billion for 1994 declined 2.1 percent compared with the prior year. The costs to produce and deliver electricity in 1994 declined by $297 million, primarily as a result of less energy being sold and continued effective cost controls. However, certain other expenses in 1994 increased compared with expenses in 1993. Depreciation expenses and property taxes increased by $41 million as a result of additional utility plant being placed into service. The work force reduction programs in 1994 increased expenses by $100 million. The amortization of deferred expenses related to Plant Vogtle increased by $39 million in 1994 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 1993, operating expenses of $6.7 billion were up 6.5 percent compared with 1992. The increase was attributable to higher production expenses of $75 million to meet increased energy demands and an additional $50 million in depreciation expenses and property taxes. The transportation fleet reduction program and environmental cleanup costs discussed earlier increased expenses by some $62 million. Also, a $67 million change in deferred Plant Vogtle expenses compared with the amount in 1992 contributed to the rise in total 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
nuclear generating units. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
1994 1993 1992 ---------------------- Total generation (billions of kilowatt-hours) 142 144 140 Sources of generation (percent) -- Coal 75 78 77 Nuclear 19 17 17 Hydro 5 4 5 Oil and gas 1 1 1 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.80 1.90 1.86 Nuclear 0.56 0.54 0.54 Oil and gas 3.99 4.34 4.81 Total 1.56 1.67 1.62 ------------------------------------------------------------
Fuel and purchased power costs of $2.3 billion in 1994 decreased $266 million or 10 percent compared with 1993, primarily because 3.1 billion fewer kilowatt-hours were needed to meet customer requirements. Also, the decrease in these costs was attributable to a lower average cost of fuel per net kilowatt-hour generated. Fuel and purchased power expenses of $2.6 billion in 1993 increased 1.3 percent compared with the prior year because of increased energy demands and a slightly higher average cost of fuel per net kilowatt-hour generated.
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 discussed earlier. For 1993, income taxes increased $69 million compared with the prior year. The increase was primarily attributable to a 1 percent increase in the corporate federal income tax rate effective January 1993, and the increase in taxable income from operations.
Total gross interest charges and preferred stock dividends continued to decline from amounts reported in the previous year. The declines are attributable to lower interest rates and significant refinancing activities in 1993 and 1992. In 1994, these costs were $765 million -- down $66 million or 8.0 percent. These costs for 1993 decreased $21 million. As a result of favorable market conditions, $1.0 billion in 1994, $3.0 billion in 1993, and $2.4 billion in 1992 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.
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 growth in energy sales to a less regulated, more competitive environment.
Georgia Power has completed three of four separate transactions to sell Unit 4 of Plant Scherer to two Florida utilities. The remaining transaction is scheduled to take place in 1995 with the after-tax gain currently estimated to total approximately $12 million. See Note 7 to the financial statements for additional information.
In 1994, work force reduction programs were implemented, reducing earnings by $61 million. These actions will assist in efforts to control growth in future operating expenses.
See Note 4 to the financial statements for information on an uncertainty regarding full recovery of an investment in the Rocky Mountain pumped storage hydroelectric project scheduled to be in commercial operation in 1995.
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 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. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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 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. 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.
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 International (Southern Electric) -- founded in 1981 -- is focusing on international and domestic cogeneration, the independent power market, and the privatization of generating facilities in the international market. During 1994, additional investments were made in entities that own and operate generating facilities in domestic and various international markets. At December 31, 1994, Southern Electric's investment in these facilities amounted to $436 million. In the near term, Southern Electric is expected to have minimal effect on earnings, but the potential exists that it could be a prime contributor to future earnings growth.
Southern Communications Services is constructing a wireless communications system to provide services beginning in 1995 to Southern Company subsidiaries and to other parties. It is anticipated that the operations of this new subsidiary, at least in its early years, will negatively affect earnings and cash flow.
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.
The ability to defer major construction projects in conjunction with regulatory precertification approval processes for both new plant additions and purchase power contracts should minimize the possibility of not being able to fully recover additional costs.
Rates to retail customers served by the system operating companies are regulated by the respective state public service commissions in Alabama, Florida, Georgia, and Mississippi. Rates for Alabama Power and Mississippi Power are adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return. See Note 3 to the financial statements for information about other retail and wholesale regulatory matters.
The Southern 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. 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 nuclear decommissioning. If current electric utility industry accounting practices for decommissioning are changed: (1) Annual provisions for decommissioning could increase. (2) The estimated cost for decommissioning may be required to be recorded as a liability in the Consolidated Balance Sheets. In
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
management's opinion -- should these changes be required -- the changes would not have a significant adverse effect on results of operations because of the company's current and expected future ability to recover decommissioning costs through rates. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information.
The company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings.
Compliance costs related to 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."
FINANCIAL CONDITION
Overview
The Southern Company's financial condition continues to remain at the strongest level since the mid-1980s. Earnings from operations continued to increase in 1994 and exceeded $1 billion. Based on this performance, in January 1995, The Southern Company board of directors increased the common stock dividend for the fourth consecutive year.
Another major change in The Southern Company's financial condition was gross property additions of $1.5 billion to utility plant. The majority of funds needed for gross property additions since 1991 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, 1994, the credit risk for derivatives outstanding was not material.
Capital Structure
The company achieved a ratio of common equity to total capitalization -- including short-term debt -- of 44.4 percent in 1994, compared with 43.8 percent in 1993 and 42.8 percent in 1992. The company's goal is to maintain the common equity ratio generally within a range of 40 percent to 45 percent.
During 1994, the operating companies sold $185 million of first mortgage bonds and, through public authorities, $749 million of pollution control revenue bonds. Preferred securities of $100 million were issued in 1994. The operating companies continued to reduce financing costs by retiring higher-cost bonds. Retirements, including maturities, of bonds totaled $973 million during 1994, $2.5 billion during 1993, and $2.8 billion during 1992. Retirements of preferred stock totaled $1 million during 1994, $516 million during 1993, and $326 million during 1992. As a result, the composite interest rate on long-term debt decreased from 8.8 percent at December 31, 1991, to 7.2 percent at December 31, 1994. During this same period, the composite dividend rate on preferred stock declined from 7.7 percent to 6.7 percent.
In 1994, The Southern Company raised $159 million from the issuance of new common stock under the company's various stock plans. An additional $120 million of new common stock was issued through a public offering in early 1994. At the close of 1994, the company's common stock had a market value of $20.00 per share, compared with a book value of $12.47 per share. The market-to-book value ratio was 160 percent at the end of 1994, compared with 184 percent at year-end 1993 and 168 percent at year-end 1992.
Capital Requirements for Construction
The construction program of the operating companies is budgeted at $1.4 billion for 1995, $1.3 billion for 1996, and $1.3 billion for 1997. The total is $4.0 billion for the three years. Actual construction costs may vary from this estimate because of factors such as changes in environmental regulations; changes in existing nuclear plants to meet new 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 will be fully recovered.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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 1,100 megawatts of capacity is planned to be completed by 1997 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 $718 million will be required by the end of 1997 for present sinking fund requirements and maturities of long-term debt. Also, the operating 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 -- will have a significant impact on The Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants will be required in two phases. Phase I compliance began in 1995 and affected eight generating plants -- some 10,000 megawatts of capacity or 35 percent of total capacity -- in the Southern electric system. 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 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 expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, which has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures were required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment will be installed on all fossil-fired units. Construction expenditures for Phase I compliance are estimated to total approximately $300 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. 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 2 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.
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 has issued
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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 nitrogen oxide controls, above Title IV requirements, on some Georgia Power plants. Final attainment rules, based on modeling studies, could require installation of additional controls for nitrogen oxide emissions to meet the 1999 deadline. A decision on new requirements is expected in 1996. 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 by November 1995. 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.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
The EPA continues to evaluate the need for a new short-term ambient air quality standard for sulfur dioxide. Preliminary results from an EPA study on the impact of a new standard indicate that a number of plants could be required to install sulfur dioxide controls. These controls would be in addition to the controls already required to meet the acid rain provision of the Clean Air Act. The EPA issued proposed rules in November 1994 and is required to take final action on this issue in 1996. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality standards for particulate matter, nitrogen oxides, 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 1995, 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 subsidiaries must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the subsidiaries could incur substantial costs to clean up properties. The subsidiaries conduct studies to determine the extent of any required cleanup costs and have recognized in their respective financial statements costs to clean up known sites. These costs for The Southern Company amounted to $8 million, $41 million, and $3 million in 1994, 1993, and 1992, 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 Brunswick, Georgia.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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
In early 1995, The Southern Company sold -- through a public offering -- common stock with proceeds totaling $103 million. The company may require additional equity capital during the remainder of 1995. The amount and timing of additional equity capital to be raised in 1995 -- 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 1995 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 subsidiaries 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.
Completing the sale of Unit 4 of Plant Scherer in 1995 will provide some $130 million of cash.
To meet short-term cash needs and contingencies, the system companies had approximately $139 million of cash and cash equivalents and $1.4 billion of unused credit arrangements with banks at the beginning of 1995.
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 1997.
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CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1994, 1993, and 1992 The Southern Company and Subsidiary Companies 1994 Annual Report
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CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994, 1993, and 1992 The Southern Company and Subsidiary Companies 1994 Annual Report
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CONSOLIDATED BALANCE SHEETS At December 31, 1994 and 1993 The Southern Company and Subsidiary Companies 1994 Annual Report
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CONSOLIDATED BALANCE SHEETS (continued) At December 31, 1994 and 1993 The Southern Company and Subsidiary Companies 1994 Annual Report
II-19
CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 1994 and 1993 The Southern Company and Subsidiary Companies 1994 Annual Report
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CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 1994 and 1993 The Southern Company and Subsidiary Companies 1994 Annual Report
CONSOLIDATED STATEMENTS OF PAID-IN CAPITAL For the Years Ended December 31, 1994, 1993, and 1992
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NOTES TO FINANCIAL STATEMENTS The Southern Company and Subsidiary Companies 1994 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), and The Southern Development and Investment Group (SDIG). 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, beginning in mid-1995, will provide digital wireless communications services -- over the 800-megahertz frequency band -- to The Southern Company's subsidiaries and also will market these services to the public within the Southeast. Southern Electric designs, builds, owns, and operates power production 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. SDIG 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.
All material intercompany items have been eliminated in consolidation. Consolidated retained earnings at December 31, 1994, include $2.8 billion of undistributed retained earnings of subsidiaries.
Certain prior years' data presented in the consolidated financial statements have been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Southern 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 Consolidated Balance Sheets at December 31 relate to:
1994 1993 ---------------- (in millions) Deferred income taxes $1,454 $1,546 Deferred Plant Vogtle costs 432 507 Premium on reacquired debt 298 288 Demand-side programs 97 49 Department of Energy assessments 79 87 Vacation pay 70 73 Deferred fuel charges 51 83 Postretirement benefits 41 22 Work force reduction costs 15 5 Deferred income tax credits (987) (1,051) Storm damage reserve (53) (22) Other, net 108 91 ------------------------------------------------------------- Total $1,605 $1,678 =============================================================
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 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 1994, uncollectible accounts continued to average less than 1 percent of revenues.
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NOTES (continued) The Southern Company and Subsidiary Companies 1994 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 $152 million in 1994, $137 million in 1993, and $132 million in 1992. 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, 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, 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 remaining liability at December 31, 1994, under this law to be approximately $43 million and $33 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 3.2 percent in 1994 and 3.3 percent in both 1993 and 1992. 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.
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 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, 1994, 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 $409 $241 $193 Non-radiated structures 75 34 43 Other 94 60 49 -------------------------------------------------------------- Total $578 $335 $285 ============================================================== (in millions) Ultimate costs: Radiated structures $1,258 $641 $ 843 Non-radiated structures 231 91 190 Other 289 160 215 -------------------------------------------------------------- Total $1,778 $892 $1,248 ==============================================================
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NOTES (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
Plant Plant Plant Farley Hatch Vogtle --------------------------- (in millions)
Amount expensed in 1994 $18 $6 $6
Accumulated provisions: Balance in external trust funds $ 71 $33 $22 Balance in internal reserves 51 29 10 ---------------------------------------------------------------- Total $122 $62 $32 ================================================================
Assumed in ultimate costs: 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. The decommissioning costs approved for ratemaking are $578 million for Plant Farley, $184 million for Plant Hatch, and $155 million for Plant Vogtle. These amounts for Georgia Power are the costs to decommission the radioactive portions of the plants based on 1990 site studies. Georgia Power's estimated ultimate costs, based on the 1990 studies, were $872 million and $1.4 billion for plants Hatch and Vogtle, respectively. Georgia Power 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 regulatory requirements, changes in technology, and changes in costs of labor, materials, and equipment.
Income Taxes
The companies provide 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.
Effective January 1, 1993, The Southern Company adopted FASB Statement No. 109, Accounting for Income Taxes. Statement No. 109 required, among other things, conversion to the liability method of accounting for accumulated deferred income taxes. See Note 9 for additional information about Statement No. 109.
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. 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. See Note 3 for additional information regarding Georgia Power's 1991 rate order. 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. 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:
1994 1993 1992 ------------------------------- (in millions) Deferred capacity buybacks $ 10 $ 38 $100 Amortization of deferred costs (85) (74) (69) Income taxes - - (23) ------------------------------------------------------------------- Net (amortization) deferred (75) (36) 8 Effect of adoption of FASB Statement No. 109 - 160 - Deferred costs at beginning of year 507 383 375 ------------------------------------------------------------------ Deferred costs at end of year $432 $507 $383 ==================================================================
Each GPSC order called for recovery of deferred costs within 10 years. Also, the orders authorized Georgia Power to impute a return similar to allowance for funds used during construction (AFUDC) on its investment in Plant Vogtle units 1 and 2 after the units began commercial operation.
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
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NOTES (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
depreciation expense. The composite rates used by the operating companies to calculate AFUDC during the years 1992 through 1994 ranged from a before-income-tax rate of 5.0 percent to 11.3 percent. AFUDC, net of income tax, as a percent of consolidated net income was 2.3 percent in 1994, 1.7 percent in 1993, and 1.8 percent in 1992.
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
In accordance with FASB Statement No. 107, Disclosure About Fair Value of Financial Instruments, The Southern Company's only financial instrument that the carrying amount did not approximate fair value at December 31 was as follows:
Long-Term Debt ----------------------- Carrying Fair Year Amount Value ---- -------- ----- (in millions) 1994 $7,674 $7,373 1993 7,321 7,729 ----------------------------------------------------------------
The fair value of 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.
Vacation Pay
The operating companies' employees earn their vacation in one year and take it in the subsequent year. However, for ratemaking purposes, vacation pay is recognized as an allowable expense only when paid. Consistent with this ratemaking treatment, the companies accrue a current liability for earned vacation pay and record a current regulatory asset representing the future recoverability of this cost. The amount was $70 million and $73 million at December 31, 1994 and 1993, respectively. In 1995, an estimated 69 percent of the 1994 deferred vacation cost will be expensed, and the balance will be charged to construction and other accounts.
2. RETIREMENT BENEFITS
Pension Plan
The system companies have defined benefit, trusteed, non-contributory pension plans that cover 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. 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
The system companies also provide 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 or to the extent required by the operating companies' respective regulatory commissions. Amounts funded are primarily invested in debt and equity securities.
Effective January 1, 1993, the system companies adopted FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. Statement No. 106 requires that medical care and life insurance benefits for retired employees be accounted for on an accrual basis
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NOTES (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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 would be expensed in 1993 and the remaining costs would be deferred. An additional one-fifth of the costs would be 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.
Prior to 1993, the system companies, except for Georgia Power and Savannah Electric, recognized these benefit costs on an accrual basis using the "aggregate cost" actuarial method, which spreads the expected cost of such benefits over the remaining periods of employees' service as a level percentage of payroll costs. Consistent with regulatory treatment in those years, Georgia Power and Savannah Electric recognized these costs on a cash basis as payments were made. The total costs of such benefits recognized by system companies in 1992 were $42 million.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension and postretirement medical and life 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 -------------------- 1994 1993 -------------------- (in millions) Actuarial present value of benefit obligation: Vested benefits $1,593 $1,534 Non-vested benefits 68 76 ---------------------------------------------------------------------- Accumulated benefit obligation 1,661 1,610 Additional amounts related to projected salary increases 638 558 ---------------------------------------------------------------------- Projected benefit obligation 2,299 2,168 Less: Fair value of plan assets 3,171 3,337 Unrecognized net gain (789) (1,060) Unrecognized prior service cost 64 72 Unrecognized transition asset (139) (152) ---------------------------------------------------------------------- Prepaid asset recognized in the Consolidated Balance Sheets $ 8 $ 29 ======================================================================
Postretirement Medical ----------------------- 1994 1993 ----------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $293 $243 Employees eligible to retire 40 48 Other employees 367 389 ------------------------------------------------------------------- Accumulated benefit obligation 700 680 Less: Fair value of plan assets 128 95 Unrecognized net loss (gain) 22 76 Unrecognized transition obligation 394 419 ------------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $156 $ 90 ===================================================================
Postretirement Life -------------------- 1994 1993 -------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $ 82 $ 75 Employees eligible to retire - - Other employees 92 96 ------------------------------------------------------------------- Accumulated benefit obligation 174 171 Less: Fair value of plan assets 12 2 Unrecognized net loss (gain) (19) (13) Unrecognized transition obligation 106 113 ------------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $ 75 $ 69 ===================================================================
The weighted average rates assumed in the actuarial calculations were:
1994 1993 1992 -------------------------------------- Discount 8.0% 7.5% 8.0% Annual salary increase 5.5 5.0 6.0 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 10.5 percent for 1994 decreasing gradually to 6.0 percent through the year 2000 and remaining at that level thereafter. An annual increase in the assumed
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NOTES (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
medical care cost trend rate of 1 percent would increase the accumulated medical benefit obligation at December 31, 1994, by $130 million and the aggregate of the service and interest cost components of the net retiree medical cost by $18 million.
Components of the plans' net costs are shown below:
Pension ----------------------- 1994 1993 1992 ------------------------ (in millions) Benefits earned during the year $ 77 $ 76 $ 75 Interest cost on projected benefit obligation 160 156 146 Actual (return) loss on plan assets 75 (432) (135) Net amortization and deferral (351) 186 (85) ---------------------------------------------------------------- Net pension cost (income) $ (39) $ (14) $ 1 ================================================================
Of the above net pension amounts, pension income of $29 million in 1994 and $9 million in 1993, and pension expense of $2 million in 1992, were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Medical ---------------------- 1994 1993 ---------------------- (in millions) Benefits earned during the year $ 26 $ 21 Interest cost on accumulated benefit obligation 51 43 Amortization of transition obligation 21 22 Actual (return) loss on plan assets 2 (12) Net amortization and deferral (10) 5 ----------------------------------------------------------------- Net postretirement cost $ 90 $ 79 =================================================================
Postretirement Life --------------------- 1994 1993 -------------------- (in millions) Benefits earned during the year $ 5 $ 6 Interest cost on accumulated benefit obligation 13 13 Amortization of transition obligation 6 6 Actual (return) loss on plan assets - - Net amortization and deferral - - ----------------------------------------------------------------- Net postretirement cost $24 $25 =================================================================
Of the above net postretirement medical and life insurance costs recorded in 1994 and 1993, $77 million and $64 million were charged to operating expenses, $18 million and $21 million were deferred, and the remainder was charged to construction and other accounts, respectively.
Work Force Reduction Programs
The system companies have incurred additional costs for work force reduction programs. The costs related to these programs were $112 million, $35 million, and $37 million for the years 1994, 1993, and 1992, respectively. A portion of the cost of these programs was deferred and is being amortized in accordance with regulatory treatment. The unamortized balance of these costs was $15 million at December 31, 1994.
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 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. This action is still pending.
Alabama Power Heat Pump Financing Suit
In September 1990, two customers of Alabama Power filed a civil complaint in the Circuit Court of Shelby County, Alabama, against Alabama Power seeking to represent all persons who, prior to June 23, 1989, entered into agreements with Alabama Power for the financing of heat pumps and other merchandise purchased from vendors other than Alabama Power. The plaintiffs contended that Alabama Power was required to obtain a license under the Alabama Consumer Finance Act to
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NOTES (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
engage in the business of making consumer loans. The plaintiffs were seeking an order declaring these agreements null and void and requiring Alabama Power to refund all payments -- principal and interest -- made under these agreements. The aggregate amount under these agreements, together with interest paid, currently is estimated to be $40 million.
In June 1993, the court ordered Alabama Power to refund or forfeit interest of approximately $10 million because of Alabama Power's failure to obtain such license. However, the court's order did not require any refund or forfeiture with respect to any principal payments under the agreements at issue. Alabama Power has appealed the court's order to the Supreme Court of Alabama.
The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material adverse effect on the company's financial statements.
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power 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. 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.
The final outcome of this matter cannot now be determined; however, in management's opinion -- based on the nature and extent of Georgia Power's activities relating to the site -- the final outcome will not have a material adverse effect on the company's financial statements.
Georgia Power Tax Litigation
In June 1994, a tax deficiency notice was received from the Internal Revenue Service (IRS) for the years 1984 through 1987 with regard to the tax accounting by Georgia Power 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 $28 million and $32 million, respectively. The tax deficiency relates to a timing issue as to when taxes are paid; therefore only the interest portion could affect future income. Management believes that the IRS position is incorrect, and Georgia Power has filed a petition with the U. S. Tax Court challenging the IRS position. In order to minimize additional interest charges should the IRS's position prevail, Georgia Power made a payment to the IRS related to the potential tax deficiency in September 1994.
The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material adverse effect on the company's financial statements.
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 last rate adjustment was effective in January 1992. 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 1994, the APSC issued an order -- at Alabama Power's request -- allowing Alabama Power to establish a natural disaster reserve not to exceed $32 million and to change the procedure for estimating the accrual of revenues for service rendered but unbilled at the end of each month. This change increased unbilled revenues for September 1994 by $28 million, which offset the initial accrual for the natural disaster reserve for the same amount. Additional monthly accruals of $250 thousand will be made until the reserve maximum is attained. In addition, a moratorium on rate increases through the third quarter of 1995 was approved.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
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
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NOTES (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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 until the superior court's decision is reversed or until the next general rate case proceedings. An association of industrial customers filed a petition for review of the accounting order in superior court.
In July 1994, the Georgia Court of Appeals upheld the legality of the rate riders. In November 1994, the Supreme Court of Georgia denied petitions for review of this ruling. As a result, Georgia Power resumed collection under the rate riders in December 1994. In early 1995, the GPSC initiated a true-up proceeding to review Georgia Power's demand-side conservation program costs both incurred and expected to be incurred during 1995 in order to adjust rate riders accordingly. The proceeding will also address a plan for recovery of costs deferred under the accounting order. Georgia Power's costs related to these conservation programs through 1994 were $115 million, of which $18 million has been collected and the remainder deferred.
The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material adverse effect on the company's financial statements.
Georgia Power 1991 Rate Order; Phase-In Plan Modifications
Georgia Power received a rate order in 1991 from the GPSC that modified the Plant Vogtle phase-in plans to begin earlier amortization of the costs deferred under the plans. The amortization period began October 1991 -- rather than October 1994 as originally scheduled -- and extends through September 1999. In addition, the GPSC ordered the levelization of capacity buyback expense from the co-owners of Plant Vogtle over a six-year period beginning October 1991. This results in net cost deferrals during the first three years and subsequent amortization of the deferred amounts in the last three years.
Mississippi Power Retail Rate Adjustment Plan
Mississippi Power's retail base rates have been set under a Performance Evaluation Plan (PEP) since 1986 with various modifications. In January 1994, the Mississippi Public Service Commission (MPSC) approved PEP-2. Under PEP-2, Mississippi Power's rate of return is measured on retail net investment. Also, three indicators are used to evaluate Mississippi Power's performance with emphasis on price and service to the customer. In addition, PEP-2 provides for the sharing of rate adjustments based on low rates and on the performance rating. The evaluation periods for PEP-2 are semiannual. Any change in rates is limited to 2 percent of retail revenues per period. PEP-2 will remain in effect until the MPSC modifies or terminates the plan.
FERC Reviews 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 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 began in October 1994 and is scheduled to continue until January 1996.
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 $77 million at December 31, 1994. Although the final outcome of this matter cannot now be determined, in management's opinion, the final outcome will not result in
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changes that would have a material adverse effect on the company's financial statements.
4. CONSTRUCTION PROGRAM
General
The operating companies are engaged in continuous construction programs, currently estimated to total some $1.4 billion in 1995, $1.3 billion in 1996, and $1.3 billion in 1997. These estimates include AFUDC of $40 million in 1995, $30 million in 1996, and $33 million in 1997. 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, 1994, 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 1,100 megawatts is planned to be completed by 1997. In addition, 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.
Rocky Mountain Project Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky Mountain pumped storage hydroelectric project 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 project. 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 project, as discussed in Note 6. However, full recovery of Georgia Power's costs depends on the GPSC's treatment of the project's costs and the disposition of the project's capacity output. In the event the GPSC does not allow full recovery of the project costs, then the portion not allowed may have to be written off. AFUDC accrued on the Rocky Mountain project has not been credited to income or included in the project cost since December 1985. If accrual of AFUDC is not resumed, Georgia Power's portion of the estimated total plant additions at completion would be approximately $200 million. The plant is scheduled to be in commercial operation in 1995.
The ultimate outcome of this matter cannot now be determined.
5. FINANCING, INVESTMENT, AND COMMITMENTS
General
In early 1995, The Southern Company sold -- through a public offering -- 5 million shares of common stock with proceeds totaling $103 million. The company may require additional equity capital during the remainder of 1995. The amount and timing of additional equity capital to be raised in 1995 -- 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 will be utilized if necessary; the amounts available are discussed below. The subsidiary 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's investments in generating facilities in domestic and various foreign markets were approximately $436 million at December 31, 1994. The consolidated financial statements reflect these investments in majority-owned or controlled subsidiaries on a consolidated basis and other investments on an equity basis.
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Bank Credit Arrangements
At the beginning of 1995, unused credit arrangements with banks totaled $1.4 billion, of which approximately $875 million expires at various times during 1995 and 1996; $41 million expires at May 1, 1997; $25 million expires at May 31, 1997; $400 million expires at June 30, 1997; and $40 million expires at December 1, 1997.
Georgia Power's revolving credit agreements of $60 million, of which $41 million remained unused as of December 31, 1994, expire May 1, 1997. 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 has $25 million of revolving credit agreements expiring May 31, 1997. 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, 1997, is under revolving credit arrangements with several banks providing 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, $135 million and $165 million of the $400 million available credit are currently dedicated to the exclusive use of 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.
Mississippi Power has $40 million of revolving credit agreements expiring December 1, 1997. 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 $11 million remained unused as of December 31, 1994, expire December 31, 1996. 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 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.
A portion of the $1.4 billion unused credit arrangements with banks -- discussed earlier -- is dedicated to provide liquidity support to the companies' variable rate pollution control bonds. The amount of credit lines dedicated at December 31, 1994, was $293 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 Alabama Power and Georgia Power, through commercial paper programs that have the liquidity support of committed bank credit arrangements.
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Assets Subject to Lien
The operating 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.
Fuel Commitments
To supply a portion of the fuel requirements of the system's generating plants, the subsidiary companies have 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 were approximately $16 billion at December 31, 1994. Additional commitments for coal and nuclear fuel will be required in the future to supply the operating companies' fuel needs.
To take advantage of lower-cost coal supplies, agreements were reached in 1986 for the payment of $121 million to terminate two contracts for the supply of coal to Plant Daniel, which is jointly owned by Gulf Power and Mississippi Power. Also, in March 1988, Gulf Power made an advance payment of $60 million to a coal supplier under an agreement to lower the cost of future coal purchased under an existing contract. These amounts are being amortized to expense.
Operating Leases
The operating companies have entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $15 million, $11 million, and $9 million for 1994, 1993, and 1992, respectively. At December 31, 1994, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts --- ----------- (in millions) 1995 $ 18 1996 17 1997 17 1998 17 1999 17 2000 and thereafter 242 ------------------------------------------------------- Total minimum payments $328 =======================================================
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 (MEAG), and the city of Dalton, Georgia. Georgia Power has completed three of four separate transactions to sell Unit 4 of Plant Scherer to two Florida utilities. See Note 7 for additional information concerning these sales. 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, both of which are discussed later.
At December 31, 1994, 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% $3,289 $628 Plant Hatch (nuclear) 50.1 842 346 Plant Miller (coal) Units 1 and 2 91.8 708 264 Plant Scherer (coal) Units 1 and 2 8.4 112 36 Unit 4 16.6 119 18 Plant Wansley (coal) 53.5 287 129 Rocky Mountain (pumped storage) 25.0* 199 - ------------------------------------------------------------- *Estimated ownership at date of completion.
Georgia Power and OPC have a joint ownership agreement regarding the 848-megawatt Rocky Mountain pumped storage hydroelectric project. Under the agreement, Georgia Power will retain its present investment in the project and OPC will finance, complete, and operate the facility. Upon completion, Georgia
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Power will own an undivided interest in the project equal to the proportion its investment bears to the total investment in the project (excluding each party's cost of funds and ad valorem taxes). Based on current cost estimates, Georgia Power's final ownership is estimated at approximately 25 percent of the project at completion. The plant is scheduled to be in commercial operation in 1995.
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 in early 1996, and will be constructed, operated, and maintained by FPC. Georgia Power will have a 33 percent interest 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. Also, Georgia Power entered into a separate four-year purchase power contract with FPC. Beginning in 1996, Georgia Power will purchase 400 megawatts of capacity. In 1998, this amount will decline to 200 megawatts for the remaining two years.
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.
In connection with a joint ownership arrangement at Plant Vogtle, Georgia Power has remaining commitments to purchase declining fractions of OPC's and MEAG's capacity and energy from this plant for periods of up to 10 years following commercial operation (and, with regard to a portion of the 5 percent additional 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 such capacity are required whether any capacity is available. The energy cost of these purchases 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 in the Consolidated Statements of Income. Capacity payments totaled $129 million, $183 million, and $289 million for 1994, 1993, and 1992, respectively. Projected capacity payments for the next five years are as follows: $77 million in 1995; $70 million in 1996; $59 million in 1997; $59 million in 1998; and $59 million in 1999. Also, a portion of the above capacity payments relates to Plant Vogtle costs that were written off after being disallowed for retail ratemaking purposes.
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 and $100 million in 1992. In 1994, the amount deferred was exceeded by the amortization of amounts previously deferred by almost $1 million. The projected net amortization of the deferred expense is $49 million in 1995, $62 million in 1996, and $57 million in 1997.
7. SALES OF INTERESTS IN PLANT SCHERER
Georgia Power has completed three 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, including any gains on these transactions. FP&L would eventually own approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
Closing Percent Date Capacity Ownership Amount ------ -------- --------- ------- (megawatts) (in millions) July 1991 290 35.46% $291 June 1993 258 31.44 253 June 1994 135 16.55 133 June 1995 135 16.55 131 ------------------------------------------------------------- Total 818 100.00% $808 =============================================================
Plant Scherer -- a jointly owned coal-fired generating plant -- has four units with a total capacity of 3,272 megawatts. Unit 4 was completed in 1989. See Note 6 for information regarding current plant ownership.
8. LONG-TERM POWER SALES AGREEMENTS
The operating subsidiaries of The Southern Company 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
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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 capacity revenues have been as follows:
Unit Other Year Power Long-Term Total ---- ---------------------------------- (in millions) 1994 $257 $19 $276 1993 312 38 350 1992 435 22 457
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 1,700 megawatts of capacity is scheduled to be sold during 1995. Thereafter, these sales will decline to some 1,600 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.
9. 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, 1994, the tax- related regulatory assets and liabilities were $1.5 billion and $1.0 billion, 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:
1994 1993 1992 ------------------------- (in millions) Total provision for income taxes: Federal -- Currently payable $603 $424 $343 Deferred -- current year 67 224 225 -- reversal of prior years (75) (51) (41) Deferred investment tax credits - (20) (6) ------------------------------------------------------------------- 595 577 521 ------------------------------------------------------------------- State -- Currently payable 86 64 50 Deferred -- current year 15 39 46 -- reversal of prior years (11) (3) (9) ------------------------------------------------------------------- 90 100 87 ------------------------------------------------------------------- Total 685 677 608 Less income taxes charged (credited) to other income (26) (57) (39) ------------------------------------------------------------------- Federal and state income taxes charged to operations $711 $734 $647 ===================================================================
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:
1994 1993 ----------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $2,637 $2,496 Property basis differences 1,647 1,741 Deferred plant costs 141 161 Other 271 289 ------------------------------------------------------------------ Total 4,696 4,687 ------------------------------------------------------------------ Deferred tax assets: Federal effect of state deferred taxes 104 102 Other property basis differences 278 292 Deferred costs 79 69 Pension and other benefits 63 46 Other 225 210 ------------------------------------------------------------------ Total 749 719 ------------------------------------------------------------------ Net deferred tax liabilities 3,947 3,968 Portion included in current assets, net 60 11 ------------------------------------------------------------------ Accumulated deferred income taxes in the Consolidated Balance Sheet $4,007 $3,979 ==================================================================
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Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Consolidated Statements of Income. Credits amortized in this manner amounted to $42 million in 1994, $36 million in 1993, and $41 million in 1992. At December 31, 1994, 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:
1994 1993 1992 --------------------------- Federal statutory rate 35.0% 35.0% 34.0% State income tax, net of federal deduction 3.3 3.7 3.4 Non-deductible book depreciation 1.8 1.9 2.2 Difference in prior years' deferred and current tax rate (1.5) (1.3) (1.5) Other 0.3 (1.1) (1.6) --------------------------------------------------------------- Effective income tax rate 38.9% 38.2% 36.5% ===============================================================
The Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each company's current and deferred tax expense is computed on a stand-alone basis, and consolidated tax savings are allocated to each company based on its ratio of taxable income to total consolidated taxable income.
10. 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, 1994, a total of 15 million shares was reserved for issuance pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee Savings Plan, 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. Currently, 36 employees are eligible to participate in the plan. As of December 31, 1994, 42 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 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 1993 and 1994 is summarized below:
Shares Average Subject Option Price To Option Per Share --------------------------- Balance at December 31, 1992 1,189,122 $15.02 Options granted 359,492 21.22 Options canceled -- -- Options exercised (183,804) 14.14 -------------------------------------------------------------------- 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 ==================================================================== Shares reserved for future grants: At December 31, 1992 4,073,936 At December 31, 1993 3,714,444 At December 31, 1994 3,268,001 -------------------------------------------------------------------- Options exercisable: At December 31, 1993 475,795 At December 31, 1994 793,989 --------------------------------------------------------------------
Common Stock Dividend Restrictions
The income of The Southern Company is derived primarily from equity in earnings of its operating subsidiaries. At December 31, 1994, $1.8 billion of consolidated retained earnings was restricted against the payment by the operating 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 1994 Annual Report
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1994 1993 ----------------- (in millions)
Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: Collateralized -- 5.375% to 9.375% due 2004-2024 $1,179 $ 708 Variable rate (5% to 6.25% at 1/1/95) due 2011-2024 412 63 Non-collateralized -- 7.2 % to 12.25% due 2003-2014 1 650 6.75% to 10.6% due 2015-2017 828 890 5.8% due 2022 10 10 Variable rate (2.95% to 3.7% at 1/1/94) due 2011-2022 - 92 ----------------------------------------------------------------- 2,430 2,413 ----------------------------------------------------------------- Capitalized lease obligations 148 247 ----------------------------------------------------------------- Notes payable: 4.15% to 9.75% due 1994-1998 153 144 8.375% to 10% due 1997-1999 196 - Adjustable rates (14.04% at 1/1/95) due 1995 26 - Adjustable rates (4% to 7.8% at 1/1/95) due 1994-1996 133 115 Adjustable rates (5.5% to 8.14% at 1/1/95) due 1998-2019 175 43 ----------------------------------------------------------------- 683 302 ----------------------------------------------------------------- Total $3,261 $2,962 =================================================================
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 $126 million and $217 million at December 31, 1994 and 1993, respectively. At December 31, 1994, the composite interest rates for buildings and other were 9.7 percent and 10.7 percent, respectively. Sinking fund requirements and/or serial maturities through 1999 applicable to other long-term debt are as follows: $97 million in 1995; $166 million in 1996; $46 million in 1997; $29 million in 1998; and $23 million in 1999.
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:
1994 1993 ------------- (in millions) Bond improvement fund requirements $ 48 $ 51 Less: Portion to be satisfied by certifying property additions 46 3 Reacquired bonds - 25 ---------------------------------------------------------------- Cash sinking fund requirements 2 23 First mortgage bond maturities and redemptions 130 44 Other long-term debt maturities (Note 11) 97 89 ---------------------------------------------------------------- Total $229 $156 ================================================================
The first mortgage bond improvement (sinking) fund requirements amount to 1 percent of each outstanding series of bonds authenticated under the indentures prior to January 1 of each year, other than those issued to collateralize pollution control and other obligations. The requirements may be satisfied by depositing cash or reacquiring bonds, or by pledging additional property equal to 166 2/3 percent of such requirements.
13. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The act provides funds up to $8.9 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. A company could be assessed up to $79 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium
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taxes, for Alabama Power and Georgia Power -- based on its ownership and buyback interests -- is $159 million and $163 million, respectively, per incident but not more than an aggregate of $20 million and $21 million, respectively, 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 $12 million and $15 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 $27 million and $25 million, respectively. The maximum replacement power assessments are $10 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.
14. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1994 and 1993 are as follows:
Earnings for 1994 declined by $61 million or 9 cents per share as a result of work force reduction programs primarily recorded in the first quarter. *Common stock data reflect a two-for-one stock split in the form of a stock distribution for each share held as of February 7, 1994. The company's business is influenced by seasonal weather conditions.
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The Southern Company and Subsidiary Companies 1994 Annual Report (See Note Below)
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The Southern Company and Subsidiary Companies 1994 Annual Report (See Note Below)
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The Southern Company and Subsidiary Companies 1994 Annual Report (See Note Below)
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The Southern Company and Subsidiary Companies 1994 Annual Report (See Note Below)
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued) The Southern Company and Subsidiary Companies 1994 Annual Report
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CONSOLIDATED STATEMENTS OF INCOME The Southern Company and Subsidiary Companies
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CONSOLIDATED STATEMENTS OF INCOME The Southern Company and Subsidiary Companies
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CONSOLIDATED STATEMENTS OF INCOME The Southern Company and Subsidiary Companies
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CONSOLIDATED STATEMENTS OF CASH FLOWS The Southern Company and Subsidiary Companies
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CONSOLIDATED STATEMENTS OF CASH FLOWS The Southern Company and Subsidiary Companies
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CONSOLIDATED STATEMENTS OF CASH FLOWS The Southern Company and Subsidiary Companies
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CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
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CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
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CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
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CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
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CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
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CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
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ALABAMA POWER COMPANY FINANCIAL SECTION
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MANAGEMENT'S REPORT Alabama Power Company 1994 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
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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, 1994 and 1993, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. 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-60 through II-78) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective January 1, 1993, the company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen LLP
Birmingham, Alabama February 15, 1995
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1994 net income after dividends on preferred stock was $356 million, representing a $10 million (2.8 percent) increase from the prior year. This improvement can be attributed to lower operating expenses which decreased 3.0 percent from the previous year as a result of the company's strategy to remain a low-cost producer of electricity. This improvement was partially offset by reduced capacity sales to nonterritorial utilities. Net income was also impacted by the mild weather in 1994.
In 1993, earnings were $346 million, representing a 2.3 percent increase over the prior year. This increase was due to higher retail energy sales and lower financing costs. These positive factors were partially offset by higher operating costs and a scheduled reduction in capacity sales to non-affiliated utilities.
The return on average common equity for 1994 was 13.86 percent compared to 13.94 percent in 1993, and 14.02 percent in 1992.
Revenues
The following table summarizes the principal factors that affected operating revenues for the past three years:
=============================================================== Increase (Decrease) From Prior Year ------------------------------------- 1994 1993 1992 ------------------------------------- (in thousands) Retail -- Change in base rates $ -- $ -- $ 36,348 Unbilled adjustment 28,000 -- -- Sales growth 45,304 24,960 36,237 Weather (39,964) 58,536 (42,709) Fuel cost recovery and other (84,344) 96,437 (31,318) ---------------------------------------------------------------- Total retail (51,004) 179,933 (1,442) ---------------------------------------------------------------- Sales for Resale -- Non-affiliates (9,345) (43,686) (121) Affiliates (17,213) 23,887 (1,287) ---------------------------------------------------------------- Total sales for resale (26,558) (19,799) (1,408) Other operating revenues 5,095 635 2,896 ---------------------------------------------------------------- Total operating revenues $(72,467) $160,769 $ 46 ================================================================ Percent change (2.4)% 5.6% -- % ================================================================
Retail revenues of $2.4 billion in 1994 decreased $51 million (2.1 percent) from the prior year, compared with an increase of $180 million (8.0 percent) in 1993. The mild weather during the summer of 1994 and lower fuel cost recovery were the primary reasons for the decrease in retail revenues from 1993. The extreme weather during 1993 and sales growth contributed to the increase in retail revenues over 1992. Fuel revenues, which decreased substantially in 1994, generally represent the direct recovery of fuel expense, including the fuel component of purchased energy, and therefore have no effect on net income. In September 1994, the company recorded an additional $28 million (679 million kilowatt-hours) in estimated unbilled revenues due to a change in the estimating procedure for unbilled kilowatt-hours (KWHs) and associated revenues. For additional information concerning unbilled revenues and an offsetting expense, see Note 3 under "Retail Rate Adjustment Procedures."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1994 Annual Report
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components, as well as the components of the sales to affiliated companies, were:
============================================================ 1994 1993 1992 ------------------------------------------ (in thousands)
Capacity $165,063 $187,062 $216,113 Energy 222,579 233,253 239,622 ------------------------------------------------------------ Total $387,642 $420,315 $455,735 ============================================================
Capacity revenues from non-affiliates remained relatively constant in 1994 but decreased in 1993 due to a scheduled reduction in capacity dedicated to unit power sales customers for the first five months of the year. 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.
KWH sales for 1994 and the percent change by year were as follows:
=============================================================== KWH Percent Change ----------------------------------------- 1994 1994 1993 1992 ----------------------------------------- (millions)
Residential 12,955 (1.7)% 9.2% (2.1)% Commercial 9,495 3.4 6.4 1.2 Industrial 19,181 3.2 1.8 4.3 Unbilled adjustment 679 - - - Other 184 1.1 2.8 1.2 --------- Total retail 42,494 3.3 5.1 1.6 Sales for resale - Non-affiliates 6,775 (5.2) (14.8) (4.9) Affiliates 8,433 4.3 12.1 (7.4) --------- Total 57,702 2.4% 3.0% (0.7)% ===============================================================
Expenses
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.
Total operating expenses for 1993 were up 7.0 percent over those recorded in 1992. The increase was mainly attributable to higher production expenses of $95 million to meet increased energy demands.
Fuel costs are 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. 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. Fuel expense increased in 1993 as a result of increased energy demands during the summer. Fuel cost per KWH generated was 1.56 cents in 1994, 1.73 cents in 1993 and 1.64 cents in 1992.
Purchased power consists primarily of purchases from the affiliates of the Southern electric system. Purchased power transactions among the company and its affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at each company. Purchased capacity from affiliates increased $5 million in 1994. KWH purchases from affiliates decreased 27 percent from the prior year.
Other operation expenses decreased 2.5 percent in 1994 following a 5.6 percent increase in 1993. The increase in 1993 was primarily the result of environmental cleanup costs, net expenses of a March snowstorm, and the one-time cost of a transportation fleet reduction program, which together totaled $16.1 million.
Maintenance expenses increased 3.8 percent in 1994 over the previous year due to the establishment of a Natural Disaster Reserve. For additional information concerning the Natural Disaster Reserve, see Note 3 under "Retail Rate Adjustment Procedures."
Depreciation and amortization expense remained virtually unchanged from the previous year. This is the result of lower average depreciation rates effective January 1994 offset by growth in depreciable plant in service. Depreciation and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1994 Annual Report
amortization expense increased 3.4 percent in 1993 due principally to growth in depreciable plant in service.
Income taxes increased in 1994 by $17 million (8.2 percent). This is due to higher taxable income. The increase in income tax expense of 2.6 percent for 1993 was primarily attributable to a one percent increase in the corporate federal income tax rate effective January 1, 1993.
The company contributed $13.5 million to the Alabama Power Foundation, Inc. in 1994, which represents an increase of $10.5 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 continued to decline from amounts reported in the previous year. The declines reflect the significant refinancing activities in 1993 and 1992. In 1994, these costs were $236 million -- down $23 million (9.0 percent). These costs decreased $7.5 million (2.8 percent) in 1993.
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 growth in energy sales 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 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. 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 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 may enhance 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. In order to address these initiatives, numerous questions must be resolved with the most complex ones relating to transmission pricing, recovery of stranded investments, and developing rate structures for different market segments that reflect the economic costs of serving that market. 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 scheduled addition of five combustion turbine generating units in 1995 and four more 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1994 Annual Report
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 regulatory matters.
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. 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 is currently reviewing the accounting for nuclear decommissioning. If current electric utility industry accounting practices for decommissioning are changed: (1) Annual provisions for decommissioning could increase. (2) The estimated cost for decommissioning may be required to be recorded as a liability in the Balance Sheets. In management's opinion -- should these changes be required -- the changes would not have a significant adverse effect on results of operations because of the company's current and expected future ability to recover decommissioning costs through rates. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate schedules and power sales contracts that the company has with its sales for resale customers. The FERC currently is reviewing the rate of return on common equity included in these schedules and contracts and may require such returns to be lowered, possibly retroactively. See Note 3 to the financial statements under "FERC Reviews Equity Returns" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air Act) could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters."
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1994. 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 $537 million in 1994. The majority of funds needed for gross property additions since 1991 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 was 47.4 percent in 1994 and 1993, compared to 47.6 percent in 1992.
In 1994, the company issued $150 million of first mortgage bonds and through public authorities, $180 million of pollution control revenue refunding bonds. Composite financing rates as of year-end for 1992 through 1994 were as follows:
================================================================ 1994 1993 1992 ------------------------------ Composite interest rate on long-term debt 7.39% 7.35% 8.00% Composite dividend rate on preferred stock 6.23% 5.80% 6.76% ================================================================
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- ==============================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1994 Annual Report
Capital Requirements
Capital expenditures are estimated to be $604 million for 1995, $500 million for 1996, and $502 million for 1997. The total is $1.6 billion for the three years. Actual capital costs may vary from this estimate because of factors such as changes in environmental regulations; changes in the existing nuclear plant to meet new 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 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 construction of combustion turbine peaking units of approximately 720 megawatts of capacity is planned by 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 $60 million will be required by the end of 1997 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, as 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 -- will have a significant impact on the Southern electric system. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants will be required in two phases. Phase I compliance began in 1995 and affected eight generating plants -- some 10,000 megawatts of capacity or 35 percent of total capacity -- in the Southern electric system. 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 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 expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, which has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures were required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment will be installed on all fossil-fired units. Construction expenditures for Phase I compliance are estimated to total approximately $300 million through 1995 for The Southern Company, of which the company's portion is approximately $30 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 anticipated Phase II limits. Therefore, during the period 1996 to 2000, compliance could require total estimated construction expenditures of $150 million for The Southern Company, of which the company's portion is approximately $80 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1994 Annual Report
An average increase of up to 2 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.
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 by November 1995. 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.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
The EPA continues to evaluate the need for a new short-term ambient air quality standard for sulfur dioxide. Preliminary results from an EPA study on the impact of a new standard indicate that a number of plants could be required to install sulfur dioxide controls. These controls would be in addition to the controls already required to meet the acid rain provision of the Clean Air Act. The EPA issued proposed rules in November 1994 and is required to take final action on this issue in 1996. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality standards for particulate matter, nitrogen oxides, 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 1995, 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.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: 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 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1994 Annual Report
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 1994 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), and The Southern Development and Investment Group (SDIG). 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 upon request to The Southern Company and to the subsidiary companies. Southern Communications, beginning in mid-1995, will provide digital wireless communications services -- over the 800-megahertz frequency band -- to The Southern Company's subsidiaries and also will market these services to the public within the Southeast. Southern Electric designs, builds, owns and operates power production 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. SDIG 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 regulated 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.
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:
================================================================ 1994 1993 -------------------- (in thousands) Deferred income taxes $451,886 $469,010 Premium on reacquired debt 101,620 102,216 Department of Energy assessments 42,996 45,554 Vacation pay 20,442 22,680 Work force reduction costs 3,664 5,468 Deferred income tax credits (405,256) (440,945) Natural disaster reserve (28,750) - Other, net 45,956 26,824 ---------------------------------------------------------------- Total $232,558 $230,807 ================================================================
In the event that a portion of the company's operations are 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 to their fair value.
Revenues and Fuel Costs
The company accrues revenues for services rendered but unbilled at the end of each fiscal period. For additional information concerning unbilled revenues, see Note 3 under "Retail Rate Adjustment Procedures."
The company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1994, uncollectible
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NOTES (continued) Alabama Power Company 1994 Annual Report
accounts continued to average less than 1 percent of revenues.
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.
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 $65 million in 1994, $62 million in 1993, and $48 million in 1992. 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 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, 1994, under this law to be approximately $43 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 1994 and 3.3 percent in both 1993 and 1992. 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.
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. Earnings on the trust fund are considered in determining decommissioning expense. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. The company has filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of retirement date. The estimated cost of decommissioning -- both site study costs and ultimate costs -- at December 31, 1994, 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 $409 Non-radiated structures 75 Other 94 -------------------------------------------------------------- Total $578 ============================================================== (in millions) Ultimate costs: Radiated structures $1,258 Non-radiated structures 231 Other 289 -------------------------------------------------------------- Total $1,778 ==============================================================
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NOTES (continued) Alabama Power Company 1994 Annual Report
(in millions) Amount expensed in 1994 $18 -------------------------------------------------------------- Accumulated provisions: Balance in external trust funds $ 71 Balance in internal reserves 51 -------------------------------------------------------------- Total $122 ==============================================================
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 regulatory requirements, changes in technology, and changes in costs of labor, materials, and equipment.
Income Taxes
The company 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.
Effective January 1, 1993, the company adopted FASB Statement No. 109, Accounting for Income Taxes. Statement No. 109 required, among other things, conversion to the liability method of accounting for accumulated deferred income taxes. See Note 8 for additional information about Statement No. 109.
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 7.9 percent in 1994, 7.8 percent in 1993, and 7.9 percent in 1992. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 1.5 percent in both 1994 and 1993 and 1.1 percent in 1992.
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 that the carrying amount did not approximate fair value at December 31 was as follows:
============================================================== Long-Term Debt ------------------------- Carrying Fair Year Amount Value ------------- ---------- (in millions)
1994 $2,446 $2,323 1993 2,315 2,439 ==============================================================
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.
Vacation Pay
The company's employees earn their vacation in one year and take it in the subsequent year. However, for ratemaking purposes, vacation pay is recognized as
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an allowable expense only when paid. Consistent with this ratemaking treatment, the company accrues a current liability for earned vacation pay and records a current regulatory asset representing future recoverability of this cost. The amount was $20 million and $23 million at December 31, 1994 and 1993, respectively. In 1995, an estimated 64 percent of the 1994 deferred vacation cost will be expensed and the balance will be charged to construction and other accounts.
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, 1994, the accumulated provision amounted to $28.8 million. Regulatory treatment by the APSC allows the company to accrue $250 thousand per month until the maximum accumulated provision of $32 million is attained. For additional information concerning the Natural Disaster Reserve, see Note 3 under "Retail Rate Adjustment Procedures."
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 "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. 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.
Effective January 1, 1993, the company adopted FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. Statement No. 106 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." Because the adoption of Statement No. 106 was reflected in rates, it did not have a material impact on net income.
Prior to 1993, the company recognized these benefit costs on an accrual basis using the "aggregate cost" actuarial method, which spreads the expected cost of such benefits over the remaining periods of employees' service as a level percentage of payroll costs. The total costs of such benefits recognized by the company in 1992 were $15.2 million.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension and postretirement medical and life 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 ------------------ 1994 1993 ------------------ (in millions) Actuarial present value of benefit obligations: Vested benefits $ 522 $ 523 Non-vested benefits 18 20 ------------------------------------------------------------ Accumulated benefit obligation 540 543 Additional amounts related to projected salary increases 174 153 ------------------------------------------------------------ Projected benefit obligation 714 696 Less: Fair value of plan assets 1,059 1,121 Unrecognized net gain (251) (349) Unrecognized prior service cost 23 25 Unrecognized transition asset (51) (56) ============================================================ Prepaid asset recognized in the Balance Sheets $ 66 $ 45 ============================================================
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=========================================================== Postretirement Medical ------------------- 1994 1993 ------------------- (in millions)
Actuarial present value of benefit obligation: Retirees and dependents $ 69 $ 67 Employees eligible to retire 22 21 Other employees 90 95 ----------------------------------------------------------- Accumulated benefit obligation 181 183 Less: Fair value of plan assets 56 39 Unrecognized net loss 6 18 Unrecognized transition obligation 96 102 ----------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 23 $ 24 ===========================================================
=========================================================== Postretirement Life ------------------ 1994 1993 ------------------ (in millions) Actuarial present value of benefit obligation: Retirees and dependents $ 27 $ 27 Other employees 29 29 ----------------------------------------------------------- Accumulated benefit obligation 56 56 Less: Fair value of plan assets 5 1 Unrecognized net gain (6) (4) Unrecognized transition obligation 24 26 ----------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 33 $ 33 ===========================================================
The weighted average rates assumed in the actuarial calculations were:
=========================================================== 1994 1993 1992 ---------------------------- Discount 8.0% 7.5% 8.0% Annual salary increase 5.5 5.0 6.0 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 10.5 percent for 1994, decreasing gradually to 6.0 percent through the year 2000 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1.0 percent would increase the accumulated medical benefit obligation as of December 31, 1994, by $33 million and the aggregate of the service and interest cost components of the net retiree medical cost by $4 million.
Components of the plans' net income are shown below:
================================================================== Pension ------------------------------------------------------------------ 1994 1993 1992 ----------------------------- (in millions) Benefits earned during the year $ 20.8 $ 20.6 $ 20.6 Interest cost on projected benefit obligation 51.2 50.4 48.2 Actual (return) loss on plan assets 23.5 (146.3) (45.8) Net amortization and deferral (116.2) 63.3 (29.3) ------------------------------------------------------------------ Net pension cost (income) $ (20.7)$ (12.0) $ (6.3) ==================================================================
Of the above net pension amounts, $(15.7) million in 1994, $(8.9) million in 1993, and $(5.1) million in 1992 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
============================================================ Postretirement Medical ------------------ 1994 1993 ------------------ (in millions)
Benefits earned during the year $ 6 $ 5 Interest cost on accumulated benefit obligation 14 12 Amortization of transition obligation 5 5 Actual (return) loss on plan assets 1 (5) Net amortization and deferral (4) 2 ------------------------------------------------------------ Net postretirement cost $22 $19 ============================================================
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============================================================= Postretirement Life ------------------ 1994 1993 ------------------ (in millions)
Benefits earned during the year $2 $2 Interest cost on accumulated benefit obligation 4 4 Amortization of transition obligation 1 1 ------------------------------------------------------------- Net postretirement cost $7 $7 =============================================================
Of the above net postretirement medical and life insurance costs recorded in 1994 and 1993, $23 million and $22 million, respectively, 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 $8.2 million, $16.1 million and $13.4 million for the years 1994, 1993 and 1992, respectively. A portion of the cost of these programs was deferred and is being amortized in accordance with regulatory treatment. The unamortized balance of these costs was $3.7 million at December 31, 1994.
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 last rate adjustment was effective in January 1992. 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 February 1993, the APSC ordered - at the company's request - a moratorium on rate increases for the first two quarters of 1993, which facilitated the transition of an accounting change. This accounting change permitted the accrual of estimated operation and maintenance expenses related to nuclear refueling outages during the period between outages rather than at the time the expenses are incurred.
Also, in 1994, the APSC issued an order - at the company's request - allowing the company to establish a natural disaster reserve not to exceed $32 million and to change the estimating procedure for unbilled kilowatt-hours and associated revenues for service rendered but unbilled at the end of each month. This change in estimate resulted in an increase in unbilled revenues for September 1994 of $28 million, which offset the initial accrual for the natural disaster reserve for the same amount. Additional monthly accruals of $250 thousand will be made until the reserve maximum is attained. In addition, a moratorium on rate increases through the third quarter of 1995 was approved.
The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
Heat Pump Financing Suit
In September 1990, two customers of the company filed a civil complaint in the Circuit Court of Shelby County, Alabama, against the company seeking to represent all persons who, prior to June 23, 1989, entered into agreements with the company for the financing of heat pumps and other merchandise purchased from vendors other than the company. The plaintiffs contended that the company was required to obtain a license under the Alabama Consumer Finance Act to engage in the business of making consumer loans. The plaintiffs were seeking an order declaring these agreements null and void and requiring the company to refund all payments -- principal and interest -- made under these agreements. The aggregate amount under these agreements, together with interest paid, currently is estimated to be $40 million.
In June 1993, the court ordered the company to refund or forfeit interest of approximately $10 million because of the company's failure to obtain such license. However, the court's order did not require any refund or forfeiture with respect to any principal payments under the agreements at issue. The company has appealed the court's order to the Supreme Court of Alabama.
The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material effect on the
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company's financial statements.
FERC Reviews 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 changes 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 began in October 1994 and is scheduled to continue until January 1996.
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 $34 million at December 31, 1994. Although the final outcome of this matter cannot now be determined; in management's opinion, the final outcome will not have a material effect on the company's financial statements.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $604 million in 1995, $500 million in 1996, and $502 million in 1997. The estimates include AFUDC of $10 million in 1995 and $9 million in both 1996 and 1997. The estimates for property additions for the three-year period includes $42.5 million committed to meeting the requirements of the Clean Air Act. 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, 1994, 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 720 megawatts is planned to be completed by 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.
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
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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, 1997. 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 provide for 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 $349 million which expire at various times during 1995 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, 1994, the company had regulatory approval to have outstanding up to $530 million of short-term borrowings.
Assets Subject to Lien
The company's mortgage, as amended and supplemented, securing the first mortgage bonds issued by the company, constitutes a direct lien on substantially all of the company's fixed property and franchises.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Total estimated long-term obligations through year 2013 were approximately $9.4 billion at December 31, 1994. Additional commitments for coal and for nuclear fuel will be required in the future to supply the company's fuel needs.
Operating Leases
The company has entered into coal rail car rental agreements with various terms and expiration dates. At December 31, 1994, estimated minimum rental commitments for noncancellable operating leases were as follows:
============================================================ Year Amounts ---- --------------- (in millions) 1995 $ 0.5 1996 2.8 1997 2.8 1998 2.8 1999 2.8 2000 and thereafter 59.5 ------------------------------------------------------------ Total minimum payments $71.2 ============================================================
6. FACILITY SALES AND 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 $74 million in 1994, $86 million in 1993 and $73 million in 1992, and is included in "Purchased power from affiliates" in the Statements of Income.
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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, 1994, the capitalization of SEGCO consisted of $54 million of equity and $78 million of long-term debt on which the annual interest requirement is $5.1 million. SEGCO paid dividends totaling $11.6 million in 1994, $11.3 million in 1993, and $12.0 million in 1992, of which one-half of each was paid to the company. SEGCO's net income was $7.2 million, $8.3 million, and $9.3 million for 1994, 1993 and 1992, respectively.
The company's percentage ownership and investment in jointly-owned generating plants at December 31, 1994, 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 $ 89 $ 39 Plant Miller Units 1 and 2 $708 $264 ----------------------------------------------------------------
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) 1994 $152 $ 7 $159 1993 144 15 159 1992 177 9 186 ================================================================
Unit power from Plant Miller is being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority (JEA) and the City of Tallahassee, Florida. Under these agreements, approximately 1,200 megawatts of capacity, a slight increase over 1994, is scheduled to be sold during 1995 and 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
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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, 1994, $146 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, 1994, the tax-related regulatory assets and liabilities were $452 million and $405 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:
================================================================= 1994 1993 1992 ------------------------------- (in thousands) Total provision for income taxes: Federal -- Currently payable $219,494 $149,680 $152,481 Deferred -- current year (48,153) 9,636 27,760 reversal of prior years 15,932 19,653 (7,827) Deferred investment tax credits (1) (2,106) - ----------------------------------------------------------------- 187,272 176,863 172,414 ----------------------------------------------------------------- State -- Currently payable 20,565 14,297 16,983 Deferred -- current year (4,067) 1,898 6,387 reversal of prior years 3,676 3,913 (2,806) ----------------------------------------------------------------- 20,174 20,108 20,564 ----------------------------------------------------------------- Total 207,446 196,971 192,978 Less income taxes credited to other income (16,834) (10,239) (8,947) ----------------------------------------------------------------- Federal and state income taxes charged to operations $224,280 $207,210 $201,925 =================================================================
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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:
=============================================================== 1994 1993 -------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $ 734 $ 697 Property basis differences 513 536 Premium on reacquired debt 38 38 Fuel clause underrecovered 4 11 Other 26 17 --------------------------------------------------------------- Total 1,315 1,299 --------------------------------------------------------------- Deferred tax assets: Capacity prepayments 36 44 Other deferred costs 27 8 Postretirement benefits 24 15 Accrued nuclear outage costs 7 7 Unbilled revenue 13 7 Other 44 39 --------------------------------------------------------------- Total 151 120 --------------------------------------------------------------- Net deferred tax liabilities 1,164 1,179 Portion included in current assets (liabilities), net 17 (14) --------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,181 $1,165 ===============================================================
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 $13 million in 1994 and 1993 and $18 million in 1992. At December 31, 1994, 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:
============================================================== 1994 1993 1992 -------------------------- Federal statutory rate 35.0% 35.0% 34.0% State income tax, net of federal deduction 2.2 2.3 2.4 Non-deductible book depreciation 1.6 1.6 1.6 Differences in prior years' deferred and current tax rates (2.9) (1.6) (1.9) Other (0.7) (2.9) (2.0) -------------------------------------------------------------- Effective income tax rate 35.2% 34.4% 34.1% ==============================================================
The Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each company's current and deferred tax expense is computed on a stand-alone basis, and consolidated tax savings are allocated to each company based on its 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:
============================================================== 1994 1993 -------------------------- (in thousands) Obligations incurred in connection with the sale of tax-exempt pollution control revenue bonds by public authorities- 2003-2013--6% to 9.375% $ 1,000 $ 27,050 2014-2024--3.05% to 10.875% 475,140 449,090 -------------------------------------------------------------- 476,140 476,140 -------------------------------------------------------------- Capitalized lease obligations: Nuclear fuel - 95,943 Office buildings 7,312 7,710 Street light 2,442 2,761 -------------------------------------------------------------- 9,754 106,414 -------------------------------------------------------------- Total $485,894 $582,554 ==============================================================
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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The company has capitalized certain office building leases and a street light lease. Monthly principal payments plus interest are required, and at December 31, 1994, the interest rate was 9.5 percent for office buildings and 13.0 percent for street lights. 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 $6.2 million and $94.7 million at December 31, 1994 and 1993, respectively. The estimated aggregate annual maturities of other long-term debt through 1999 are as follows: $0.8 million in 1995, $0.9 million in 1996, $1.0 million in 1997, $1.0 million in 1998 and $1.2 million in 1999.
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:
================================================================= 1994 1993 ------------------------ (in thousands) Bond improvement fund requirements $20,047 $20,135 Less: Portion to be satisfied by certifying property additions 20,047 - ----------------------------------------------------------------- Cash sinking fund requirements - $20,135 Other long-term debt maturities (Note 9) 796 38,863 ----------------------------------------------------------------- Total $ 796 $58,998 =================================================================
The annual first mortgage bond improvement fund requirement is one 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 1995 requirement of $20.0 million was satisfied by certification of property additions. In addition, maturing in 1995 are other long-term debt of $796 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 $12 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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that policy. The maximum annual assessments per incident under current policies for the company would be $27 million for excess property damage and $10 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 then, any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under 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 $6.4 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, 1994, $807 million of retained earnings 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 1994 and 1993 are as follows:
================================================================== Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock ------------------- --------- --------- -------------- (in thousands)
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
March 1993 $635,559 $124,356 $ 57,856 June 1993 733,589 159,023 91,448 September 1993 919,934 205,151 150,818 December 1993 718,527 106,582 46,372 ==================================================================
The company's business is influenced by seasonal weather conditions.
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ALABAMA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1994
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 1985 50,000 9-3/8% 50,000 6/1/15 1985 81,500 9-1/4% 81,500 12/1/15 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 ---------- ---------- $ 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 1994
First Mortgage Bonds Principal Interest Series Amount Rate ---------------------------------------------------- (Thousands) 1987 $ 15,243 10-5/8% 1991 1,252 9-1/4% 1991 1,500 8-3/4% 1992 2,000 8-1/2% 1992 392 8.30% -------- $ 20,387 ========
Pollution Control Bonds Principal Interest Series Amount Rate --------------------------------------------------- (Thousands) 1974 $ 18,550 6% 1976 2,900 7.20% 1978 4,600 7-1/4% 1984 100,000 10-7/8% 1989 35,000 7.20% 1989 18,700 7.20% -------- $179,750 ========
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GEORGIA POWER COMPANY FINANCIAL SECTION
II-93
MANAGEMENT'S REPORT Georgia Power Company 1994 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 five 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. As discussed in Note 4 to the financial statements, an uncertainty exists with respect to the actions of regulators regarding recoverability of the Company's investment in the Rocky Mountain pumped storage hydroelectric project. The outcome of this uncertainty cannot be determined until a regulatory review is completed. Accordingly, no provision for any write-down of the costs associated with the Rocky Mountain project resulting from the potential actions of the Georgia Public Service Commission has been made in the accompanying financial statements.
/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
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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, 1994 and 1993, 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, 1994. 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-126) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective January 1, 1993, the Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an uncertainty exists with respect to the actions of the regulators regarding recoverability of the Company's investment in the Rocky Mountain pumped storage hydroelectric project. The outcome of this uncertainty cannot be determined until a regulatory review is completed. Accordingly, no provision for any write-down of the costs associated with the Rocky Mountain project resulting from the potential actions of the Georgia Public Service Commission has been made in the accompanying financial statements.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 15, 1995
II-95
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1994 earnings totaled $526 million, representing a $44 million (7.8 percent) decrease from the prior year. This decline is primarily the result of a $55 million after-tax charge associated with the 1994 work force reduction programs. The Company had lower operating expenses and financing costs in 1994, partially offset by lower retail revenues due to the mild weather. Also, during the period, the Company had an $11 million after-tax gain on the sale of a portion of Plant Scherer Unit 4 compared to an $18 million after-tax gain on the sale of a portion of the plant in the prior year.
Earnings for 1993 increased over the prior year primarily as a result of higher retail revenues due to the exceptionally hot summer weather during 1993 and lower financing costs. Also, as previously discussed, 1993 earnings included an $18 million after-tax gain on the sale of a portion of Plant Scherer. These positive events were partially offset by higher operating expenses.
Revenues
The following table summarizes the factors impacting operating revenues for the 1992-1994 period:
========================================================== Increase (Decrease) From Prior Year ---------------------------------------------------------- 1994 1993 1992 -------------------------- Retail - (in millions) Change in base rates $ - $ - $ 95 Sales growth 67 45 76 Weather (128) 126 (58) Fuel cost recovery (35) 76 (26) Demand-side programs (12) 15 - ---------------------------------------------------------- Total retail (108) 262 87 ---------------------------------------------------------- Sales for resale - Non-affiliates (183) (106) (96) Affiliates (1) (6) 2 ---------------------------------------------------------- Total sales for resale (184) (112) (94) ---------------------------------------------------------- Other operating revenues 3 4 3 ---------------------------------------------------------- Total operating revenues $(289) $ 154 $ (4) ========================================================== Percent change (6.5)% 3.6% (0.1)% ----------------------------------------------------------
Retail revenues of $3.7 billion in 1994 decreased $108 million (2.8 percent) from the prior year, compared with an increase of $262 million (7.4 percent) in 1993. The milder-than-normal weather during the summer of 1994, compared to the hot summer of 1993, was the primary reason for the decrease in retail revenues. The hot weather during the summer of 1993 was the primary factor affecting the increase in retail revenues over 1992. 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 1994 and 1993. Sales to municipalities and cooperatives in Georgia 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 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:
============================================================== 1994 1993 1992 -------------------------- (in millions) Capacity $84 $152 $233 Energy 82 113 168 -------------------------------------------------------------- Total $166 $265 $401 ==============================================================
Contractual unit power sales to Florida utilities for 1994 and 1993 are down compared with prior years, primarily due to scheduled reductions that corresponded with the sales to these utilities of portions of Plant Scherer Unit 4 in June 1994 and June 1993. The amount of capacity under these contracts declined by 427 megawatts and 533 megawatts in 1994 and 1993, respectively. In 1995, the contracted capacity will decline another 155 megawatts.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1994 Annual Report
Revenues from sales to affiliated companies within the Southern electric system will vary from year to year depending on demand and the availability and cost of generating resources at each company. Sales to affiliated companies do not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 1994 and the percent change by year were as follows:
======================================================================= Percent Change ---------------------------------- KWH 1994 1993 1992 ------ ---------------------------------- (in billions) Residential 15.7 (5.8)% 11.5% 0.8% Commercial 18.7 2.5 5.9 2.2 Industrial 24.3 3.0 2.9 3.1 Other 0.5 5.0 5.7 1.7 ------ Total retail 59.2 0.4 6.1 2.2 ------ Sales for resale - Non-affiliates 8.0 (44.3) (9.8) (15.2) Affiliates 3.1 0.9 (8.8) (14.6) ------ Total sales for resale 11.1 (36.4) (9.7) (15.1) ------ Total sales 70.3 (8.0) 2.1 (2.9) ====== -----------------------------------------------------------------------
The sales decline in the residential class was primarily the result of milder-than-normal summer weather in 1994, compared to the extremely hot summer of 1993. Industrial and commercial sales were positively impacted by continued improvement in economic conditions. Residential and commercial energy sales growth in 1993 reflected hot summer weather. Industrial sales growth in 1993 is attributable to improved economic conditions which also positively influenced commercial sales. Assuming normal weather, sales to retail customers are projected to grow approximately 2 percent annually on average during 1995 through 1997.
Energy sales to non-affiliated utilities reflect reductions in contractual unit power sales and energy sales to municipalities and cooperatives, as discussed earlier.
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:
=============================================================================== 1994 1993 1992 ---------------------------------- Total generation (billions of kilowatt-hours) 62 64 63 Sources of generation (percent) -- Coal 74.8 76.9 75.9 Nuclear 21.9 20.0 20.9 Hydro 3.1 2.8 3.1 Oil and gas 0.2 0.3 0.1 Average cost of fuel per net kilowatt-hour generated (cents) -- Coal 1.67 1.75 1.75 Nuclear 0.63 0.58 0.63 Oil and gas * * * Total 1.44 1.52 1.52 -------------------------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.
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. In 1993, fuel expense increased 2.3 percent due to higher generation, which was partially offset by lower nuclear fuel costs.
Purchased power expense has decreased significantly since 1992, reflecting declining contractual capacity purchases from the co-owners of plants Vogtle and Scherer. Purchased power expense decreased $156 million in 1994 and $88 million in 1993. The decline in 1994 also results from decreased purchases from affiliated companies and energy purchases from territorial wholesale customers. The declines in Plant Vogtle contractual capacity purchases did not have a significant impact on earnings in 1994 or 1993 since these costs are being levelized over six years under the terms of the 1991 Georgia Public Service Commission (GPSC) retail rate order. The levelization is reflected in the amortization of deferred Plant Vogtle expenses in the income statements. See Note 3 to the financial statements under "Plant Vogtle Phase-In Plans" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1994 Annual Report
Other Operation and Maintenance (O & M) expenses, excluding the provision for separation benefits, decreased 4.5 percent in 1994. The decrease is 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 expenses and pension costs during 1994. Other O & M expenses increased 9.0 percent in 1993 primarily as a result of environmental remediation costs and the automotive fleet reduction program, and the recognition of higher employee benefit costs under new accounting rules adopted in 1993. See Note 2 to the financial statements under "Postretirement Benefits" for additional information concerning the new accounting rules. Also, during 1993, O & M expenses reflected costs associated with new demand-side option programs. These program costs were offset by increases in retail revenues. See Note 3 to the financial statements under "Demand-Side Conservation Programs" for additional information on the recovery of these program costs.
Taxes other than income taxes increased 1.0 percent in 1994 and 7.4 percent in 1993, reflecting primarily higher ad valorem taxes. The 1993 increase also includes higher franchise taxes paid to municipalities as a result of increased sales.
Income tax expense decreased $24 million in 1994 primarily due to lower earnings and the recognition of $17 million in tax expense associated with the sale of a portion of Plant Scherer Unit 4 in 1994, compared to $27 million in tax expense associated with the sale of a portion of the plant in the prior year. The sales resulted in after-tax gains of $11 million in 1994 and $18 million in 1993. Income tax expense increased $62 million in 1993 due primarily to higher earnings, the effect of a one percent increase in the federal tax rate effective January, 1993, and as previously discussed, the sale of a portion of Plant Scherer Unit 4.
Interest expense and dividends on preferred stock decreased $63 million (13.7 percent) and $19 million (4.0 percent) in 1994 and 1993, respectively. These reductions are primarily due to refinancing of long-term debt and preferred stock. The Company refinanced $510 million and $1.5 billion of securities in 1994 and 1993, respectively. The Company also retired $386 million of long-term debt with the proceeds from the 1994 and 1993 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.
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 1995 through 1997.
The scheduled addition of four combustion turbine generating units and the Rocky Mountain pumped storage hydroelectric project in 1995 and one jointly owned combustion turbine unit in 1996, will increase related O & M and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1994 Annual Report
depreciation expenses. In addition, the Company has entered into a four-year purchase power agreement to meet peaking needs. Beginning in 1996, the Company will purchase 400 megawatts of capacity. In 1998, this amount will decline to 200 megawatts for the remaining two years. Capacity payments are projected to be $6 million in 1996 and 1997 and $3 million in 1998 and 1999. These costs will be recorded in purchased power expenses in the Statements of Income. The Company has also reached an agreement on major terms and conditions of a purchase power arrangement whereby the Company would buy electricity during peak periods from a proposed 200 megawatt cogeneration facility, starting in June 1998. A final agreement is expected to be completed and filed with the GPSC for certification during 1995.
In 1994, work force reduction programs were implemented, reducing earnings by $55 million. These reductions will assist in efforts to control growth in future operating expenses.
As discussed in Note 4 to the financial statements, regulatory uncertainties exist related to the Rocky Mountain pumped storage hydroelectric project. In the event the GPSC does not allow full recovery of the project's costs, then the portion not allowed may have to be written off. The Company's total investment in the project at completion is estimated to be approximately $200 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 and litigation currently pending in the U. S. Tax Court.
The Company has completed three in a series of four separate transactions to sell Unit 4 of Plant Scherer to two Florida utilities. The remaining transaction is scheduled to take place in 1995. If the sale takes place as planned, the Company would realize an additional after-tax gain estimated to total approximately $12 million. This transaction coincides with scheduled reductions in capacity revenues from Florida utilities under contractual unit power sales contracts of approximately $18 million in 1995 and an additional $10 million in 1996. Additionally, the expiration in 1994 of the contract for the sale of long-term non-firm power to Florida Power Corporation will result in a $9 million decrease in capacity revenues in 1995. See Notes 5 and 6 to the financial statements for additional information.
During 1994, Oglethorpe Power Corporation (OPC) gave the Company notice of its intent to decrease its purchases of capacity under a power supply agreement. As a result, the Company's capacity revenues from OPC will decline approximately $8 million in 1996 and an additional $16 million in 1997.
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 Clean Air 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 may enhance 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. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1994 Annual Report
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 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.
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. 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 nuclear decommissioning. If current electric utility industry accounting practices for decommissioning are changed: (1) annual provisions for decommissioning could increase, and (2) the estimated cost for decommissioning may be required to be recorded as a liability in the Balance Sheets. In management's opinion -- should these changes be required -- the changes would not have a significant adverse effect on results of operations because of the Company's current and expected future ability to recover decommissioning costs through rates. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information.
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition in 1994 were gross utility plant additions of $638 million and the lowering of the cost of capital achieved through the refinancing or retirement of $654 million 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 1994, the Company continued to lower its financing costs by refinancing higher-cost issues. New issues during 1992 through 1994 totaled $3.5 billion and retirement or repayment of securities totaled $4.1 billion. The retirements included the redemption of $133 million and $253 million in 1994 and 1993, respectively, of first mortgage bonds with the proceeds from the Plant Scherer Unit 4 sales. Composite financing rates for the years 1992 through 1994, as of year-end, were as follows:
============================================================== 1994 1993 1992 ---------------------------------- Composite interest rate on long-term debt 7.14% 7.86% 8.49% Composite preferred stock dividend rate 7.11% 6.76% 7.52% ==============================================================
The Company's current securities ratings are as follows:
============================================================== Duff & Standard & Phelps Moody's Poor's First Mortgage Bonds A+ A2 A Preferred Stock A- a3 A- Unsecured Bonds A A3 A- Commercial Paper D1 P1 A1 ==============================================================
Liquidity and Capital Requirements
Cash provided from operations decreased by $128 million in 1994, primarily due to lower retail sales, higher tax payments, and the receipt in 1993 of cash payments from Gulf States as partial settlement of litigation.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1994 Annual Report
The Company estimates that construction expenditures for the years 1995 through 1997 will total $579 million, $626 million and $724 million, respectively. The Company will continue to invest in transmission and distribution facilities and enhance existing generating plants. These expenditures also include amounts for five combustion turbine generating units and equipment that will be required to comply with the provisions of the Clean Air Act.
The Company's annual contractual capacity purchases will decline by $70 million over the next three years. Cash requirements for sinking fund requirements, redemptions announced, and maturities of long-term debt are expected to total $360 million during 1995 through 1997.
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 1995 through 1997, the amount to be funded totals $16 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 $33 million as of December 31, 1994. 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 $709 million of unused credit arrangements with banks at the beginning of 1995. See Note 8 to the financial statements for additional information.
Completing the remaining transaction for the sale of Plant Scherer Unit 4 will generate approximately $131 million in 1995.
Georgia Power Capital, a limited partnership, was formed on November 10, 1994, for the purpose of issuing preferred securities and subsequently lending the proceeds to the Company. In December 1994, Georgia Power Capital issued four million shares of preferred securities at 9 percent and subsequently loaned the proceeds of $100 million to the Company. This subordinated debt of the Company is due December 19, 2024.
The Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's ability to satisfy all coverage requirements is such that it could issue new first mortgage bonds and preferred stock to provide sufficient funds for all anticipated requirements.
Environmental Issues
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- will have a significant impact on The Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants will be required in two phases. Phase I compliance began in 1995 and affected eight generating plants -- some 10,000 megawatts of capacity or 35 percent of total capacity -- in the Southern electric system. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1994 Annual Report
designed to use allowances as a compliance option.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, which has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures were required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment will be installed on all fossil-fired units. Under this Phase I compliance approach, Georgia Power's construction expenditures are estimated to total approximately $175 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 $20 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 2 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.
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 has 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 nitrogen oxide controls, above Title IV requirements, on some of the Company's plants. Final attainment rules, based on modeling studies, could require installation of additional controls for nitrogen oxide emissions to meet the 1999 deadline. A decision on new requirements is expected in 1996. 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 by November 1995. 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 continues to evaluate the need for a new short-term ambient air quality standard for sulfur dioxide. Preliminary results from an EPA study on the impact of a new standard indicate that a number of plants could be required to install sulfur dioxide controls. These controls would be in addition to the controls already required to meet the acid rain provision of the Clean Air Act. The EPA issued proposed rules in November 1994 and is required to take final action on this issue in 1996. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality standards for particulate matter, nitrogen oxides, 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 1995, 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1994 Annual Report
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, $32 million, and $3 million in 1994, 1993, and 1992, respectively. Additional sites may require environmental remediation for which the Company may be liable for a portion or all required cleanup costs. See Note 4 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 another environmental matter.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: 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.
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NOTES TO FINANCIAL STATEMENTS Georgia Power Company 1994 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), and Southern Nuclear Operating Company (Southern Nuclear), and The Southern Development and Investment Group (SDIG). 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. Intracompany contracts dealing with jointly owned generating facilities, transmission lines and 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 each of the subsidiary companies. Southern Communications, beginning in mid-1995, will provide digital wireless communications services to The Southern Company's subsidiaries and also will market these services to the public within the Southeast. Southern Electric designs, builds, owns, and operates power production 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. SDIG 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. 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 and complies with the accounting policies and practices prescribed by the respective regulatory commissions.
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:
=============================================================== 1994 1993 -------------------- (in millions) Deferred income taxes $ 920 $ 993 Deferred income tax credits (433) (453) Deferred Plant Vogtle costs 432 507 Premium on reacquired debt 165 153 Demand-side program costs 97 49 Corporate building lease 48 47 Postretirement benefits 41 22 Vacation pay 41 42 Inventory conversions (39) (47) Department of Energy assessments 36 41 Other, net 52 61 --------------------------------------------------------------- Total $1,360 $1,415 ===============================================================
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 to their fair value.
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NOTES (continued) Georgia Power Company 1994 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. Fuel costs were under recovered by $23 million and $79 million at December 31, 1994, and 1993, respectively. These amounts are included in customer accounts receivable on the Balance Sheets. The fuel cost recovery rate was increased effective December 6, 1993.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. In 1994, 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 $87 million in 1994, $75 million in 1993, and $84 million in 1992. 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 to be approximately $33 million. This obligation is recognized in the accompanying Balance Sheets and is being recovered through the fuel cost recovery provisions.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.1 percent in 1994, 1993, and 1992. 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.
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.
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NOTES (continued) Georgia Power Company 1994 Annual Report
Site study cost is the estimate to decommission the facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs at December 31, 1994, -- 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 -----------------------------------------------------------
Site study costs: (in millions) Radiated structures $241 $193 Non-radiated structures 34 43 Other 60 49 ----------------------------------------------------------- Total $335 $285 ===========================================================
Ultimate costs: (in millions) Radiated structures $641 $ 843 Non-radiated structures 91 190 Other 160 215 ----------------------------------------------------------- Total $892 $1,248 ===========================================================
(in millions) Amount expensed in 1994 $6 $6
Accumulated provisions: Balance in external trust funds $33 $22 Balance in internal reserves 29 10 ----------------------------------------------------------- Total $62 $32 ===========================================================
Assumed in ultimate costs: Inflation rate 4.4% 4.4% Trust earning 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 approved for ratemaking are $184 million for Plant Hatch and $155 million for Plant Vogtle. These amounts are based on costs to decommission the radioactive portions of the plants based on 1990 site studies. The estimated ultimate costs based on the 1990 studies were $872 million and $1.4 billion for plants Hatch and Vogtle, respectively. The Company expects the GPSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials, and equipment.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle Units 1 and 2 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.
Income Taxes
The Company 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.
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. Statement No. 109 required, among other things, conversion to the liability method of accounting for accumulated deferred income taxes. See Note 7 for additional information about Statement No. 109.
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NOTES (continued) Georgia Power Company 1994 Annual Report
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. For the years 1994, 1993 and 1992, the average AFUDC rates were 6.18 percent, 4.96 percent and 7.16 percent, respectively. The reduction in the average AFUDC rate in 1993 reflects the Company's greater use of lower cost short-term debt. 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 1994, 1993 and 1992, respectively.
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 replacement of property (exclusive of minor items of property) is charged to utility plant.
The Company's investment in generating plant, based on its ownership interests and net of the accumulated provision for depreciation, by type of generation as of December 31 was as follows:
================================================================== Nameplate Type of Generation Net Investment Capacity -------------------- ----------------- ---------------- 1994 1993 1994 1993 ----------------- ---------------- (in millions) (megawatts)
Steam $1,674 $1,718 9,676 9,812 Nuclear 3,113 3,215 1,877 1,877 Hydro 335 338 862 862 Other 123 18 1,528 1,208 ----------------------------------------------------------------- Total $5,245 $5,289 13,943 13,759 =================================================================
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:
============================================================= Long-Term Debt ------------------------- Carrying Fair Amount Value ------------------------ Year (in millions) 1994 $3,838 $3,697 1993 3,954 4,197
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.
Vacation Pay
Company employees earn vacation in one year and take it in the subsequent year. However, for ratemaking purposes, vacation pay is recognized as an allowable expense only when paid. Consistent with this ratemaking treatment, the Company accrues a current liability for earned vacation pay and records a current regulatory asset representing the future recoverability of this cost. This amount was $41 million at December 31, 1994, and $42 million at December 31, 1993. In 1995, approximately 70 percent of the 1994 deferred vacation costs will be expensed, and the balance will be charged to construction and other accounts.
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NOTES (continued) Georgia Power Company 1994 Annual Report
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 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 "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 FERC. During 1994, the Company funded $22 million to the qualified trusts. Amounts funded are primarily invested in debt and equity securities.
Effective January 1, 1993, the Company adopted FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. Statement No. 106 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 expense was recognized in 1993 and the remaining additional expense was 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.
Prior to 1993, the Company recognized these costs on a cash basis as payments were made. The total costs of such benefits recognized by the Company in 1992 were $13 million.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension and postretirement medical and life 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 =============================================================== 1994 1993 --------------------- Actuarial present value of (in millions) benefit obligations: Vested benefits $ 689 $ 655 Non-vested benefits 32 35 --------------------------------------------------------------- Accumulated benefit obligation 721 690 Additional amounts related to projected salary increases 294 257 --------------------------------------------------------------- Projected benefit obligation 1,015 947 Less: Fair value of plan assets 1,419 1,495 Unrecognized net gain (371) (490) Unrecognized prior service cost 28 31 Unrecognized transition asset (58) (62) --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 3 $ 27 ===============================================================
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NOTES (continued) Georgia Power Company 1994 Annual Report
Postretirement Medical =============================================================== 1994 1993 -------------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $168 $136 Employees eligible to retire 7 12 Other employees 191 206 --------------------------------------------------------------- Accumulated benefit obligation 366 354 Less: Fair value of plan assets 46 30 Unrecognized net loss 7 40 Unrecognized transition obligation 236 251 --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 77 $ 33 ===============================================================
Postretirement Life =============================================================== 1994 1993 --------------- (in millions) Actuarial present value of benefit obligation: Retirees and dependents $35 $32 Employees eligible to retire - - Other employees 38 40 --------------------------------------------------------------- Accumulated benefit obligation 73 72 Less: Fair value of plan assets 6 1 Unrecognized net gain (8) (6) Unrecognized transition obligation 65 69 --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $10 $ 8 ===============================================================
Weighted average rates used in actuarial calculations:
============================================================= 1994 1993 1992 ------------------------------ Discount 8.0% 7.5% 8.0% Annual salary increase 5.5 5.0 6.0 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 10.5 percent for 1994, decreasing gradually to 6 percent through the year 2000 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1.0 percent would increase the accumulated medical benefit obligation as of December 31, 1994, by $68 million and the aggregate of the service and interest cost components of the net retiree medical cost by $10 million.
The components of the plans' net costs are shown below:
Pension ============================================================================== 1994 1993 1992 ---------------------------- (in millions) Benefits earned during the year $ 34 $ 33 $ 34 Interest cost on projected benefit obligation 71 69 65 Actual (return) loss on plan assets 35 (194) (61) Net amortization and deferral (160) 84 (38) ------------------------------------------------------------------------------ Net pension cost $ (20) $ (8) $ - ==============================================================================
Net pension costs were negative in 1994 and 1993. Of net pension costs recorded, $15 million in 1994 and $6 million in 1993, were recorded as a reduction to operating expense, with the balance being recorded as a reduction to construction and other accounts.
Postretirement Medical =============================================================================== 1994 1993 -------------- (in millions) Benefits earned during the year $ 13 $ 11 Interest cost on accumulated benefit obligation 27 23 Amortization of transition obligation over 20 years 12 12 Actual (return) loss on plan assets 1 (4) Net amortization and deferral (3) 2 ------------------------------------------------------------------------------- Net postretirement cost $ 50 $ 44 ===============================================================================
Postretirement Life =============================================================================== 1994 1993 ----------- (in millions) Benefits earned during the year $ 2 $ 3 Interest cost on accumulated benefit obligation 6 6 Amortization of transition obligation over 20 years 3 3 Actual return on plan assets - - Net amortization and deferral - - ------------------------------------------------------------------------------- Net postretirement cost $11 $12 ===============================================================================
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NOTES (continued) Georgia Power Company 1994 Annual Report
Of the above net postretirement medical and life insurance costs recorded in 1994, $28 million was charged to operating expenses, $18 million was deferred, and the remainder was charged to construction and other accounts. In 1993, $21 million was charged to operating expenses, $21 million was 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 the Company's programs were $82 million and $10 million for the years 1994 and 1992, respectively. Additionally, in 1994, the Company recognized $8 million for its share of costs associated with SCS's work force reduction program.
3. LITIGATION AND REGULATORY MATTERS
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 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. An association of industrial customers filed a petition for review of the accounting order in superior court.
In July 1994, the Georgia Court of Appeals upheld the legality of the rate riders. In November 1994, the Supreme Court of Georgia denied petitions for review of this ruling. As a result, the Company resumed collection under the rate riders in December 1994. In February 1995, the GPSC initiated a true-up proceeding to review program costs which have been incurred by the Company and costs expected to be incurred during 1995 in order to adjust the rate riders accordingly. The proceeding will also address a plan for recovery of costs deferred under the accounting order. The Company's costs related to these conservation programs through 1994 were $115 million, of which $18 million has been collected and the remainder deferred.
The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material adverse effect on the Company's financial statements.
Tax Litigation
In June 1994, a tax deficiency notice was received from the Internal Revenue Service (IRS) for the years 1984 through 1987 with regard to the tax accounting by the Company 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 $28 million and $32 million, respectively. The tax deficiency relates to a timing issue as to when taxes are paid; therefore, only the interest portion could affect future income. Management believes that the IRS position is incorrect, and the Company has filed a petition with the U. S. Tax Court challenging the IRS position. In order to minimize additional interest charges should the IRS's position prevail, the Company made a payment to the IRS related to the potential tax deficiency for the years 1984 through 1987 in September 1994.
The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material adverse effect on the Company's financial statements.
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.
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NOTES (continued) Georgia Power Company 1994 Annual Report
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 is scheduled to continue until January 1996.
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 $35 million at December 31, 1994. Although the final outcome of this matter cannot now be determined, in management's opinion, the final outcome will not result in changes that would have a material adverse effect on the Company's financial statements.
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 such request is pending before the FERC. 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.
While the outcome of this matter cannot be determined, in management's opinion, it will not have a material adverse effect on the Company's financial statements.
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:
============================================================= 1994 1993 1992 --------------------------- (in millions) Deferred costs at beginning of year $507 $383 $375 -------------------------------------------------------------- Deferred capacity buyback expenses 10 38 100 Amortization of previously deferred costs (85) (74) (69) Less income taxes - - (23) -------------------------------------------------------------- Net (amortization) deferral (75) (36) 8 -------------------------------------------------------------- Effect of adoption of FASB Statement No. 109 - 160 - -------------------------------------------------------------- Deferred costs at end of year $432 $507 $383 ==============================================================
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NOTES (continued) Georgia Power Company 1994 Annual Report
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 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, 1994, the remaining amount to be collected was $5 million.
4. COMMITMENTS AND CONTINGENCIES
Rocky Mountain Project Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky Mountain pumped storage hydroelectric project 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 project. In 1988, the Company and OPC entered into a joint ownership agreement for OPC to assume responsibility for the construction and operation of the project, as discussed in Note 5. However, full recovery of the Company's costs depends on the GPSC's treatment of the project's costs and disposition of the project's capacity output. In the event the GPSC does not allow full recovery of the project's costs, then the portion not allowed may have to be written off. AFUDC accrued on the Rocky Mountain project has not been credited to income or included in the project cost since December 1985. If accrual of AFUDC is not resumed, the Company's estimated total investment in the project at completion would be approximately $200 million. The plant is scheduled to begin commercial operation in 1995.
The ultimate outcome of this matter cannot now be determined.
Construction Program
While the Company has no new baseload generating plants under construction, the construction of five combustion turbine peaking units is planned to be completed by 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 $579 million in 1995, $626 million in 1996 and $724 million in 1997. These estimated additions include AFUDC of $27 million in 1995, $17 million in 1996, and $22 million in 1997. The estimates for property additions for the three-year period include $92 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 commitments were approximately $4.6 billion at December 31, 1994. Additional commitments for coal and for nuclear fuel will be required in the future to supply the Company's fuel needs.
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NOTES (continued) Georgia Power Company 1994 Annual Report
Operating Leases
The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $13 million, $8 million, and $7 million for 1994, 1993, and 1992, respectively. At December 31, 1994, estimated minimum rental commitments for noncancelable operating leases were as follows:
====================================================== Amounts -------------- Year (in millions) ---- 1995 $ 12 1996 11 1997 10 1998 10 1999 10 2000 and thereafter 136 ------------------------------------------------------ Total minimum payments $189 ======================================================
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. 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. In management's opinion, however, based upon the nature and extent of the Company's activities relating to the site, the final outcome will not have a material adverse effect on the Company's financial statements.
In compliance with the recently enacted Georgia Hazardous Site Response Act, 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 $4 million in expenses for the anticipated clean-up cost for two sites that the Company plans 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 $3 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 sites were required to be remediated, the Company could incur expenses of up to approximately $25 million in additional clean-up costs, and construction expenditures of up to $100 million to develop new waste management facilities or install additional pollution control devices.
The final outcome of this matter cannot now be determined; however, in management's opinion, the final outcome will not have a material adverse effect on the Company's financial statements.
Nuclear Insurance
Under the Price-Anderson Amendments Act of 1988, the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plants. The act provides funds up to $8.9 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. 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 for the Company -- based on its ownership and buyback interests -- is $163 million per incident but not more than an aggregate of $21 million to be paid for each incident in any one year.
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NOTES (continued) Georgia Power Company 1994 Annual Report
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 $15 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 $25 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.
5. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
Since 1975, 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, an affiliate.
Additionally, the Company has completed three of four separate transactions to sell Unit 4 of Plant Scherer to Florida Power & Light Company (FPL) and Jacksonville Electric Authority (JEA) for a total price of approximately $808 million, including any gains on these transactions. FPL will eventually own approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
============================================================= Closing Percent After-Tax Date Capacity Ownership Amount Gain ------------------------------------------------------------- (in megawatts) (in millions) July 1991 290 35.46% $291 $14 June 1993 258 31.44 253 18 June 1994 135 16.55 133 11 June 1995 135 16.55 131 12 ------------------------------------------------------------- Total 818 100.00% $808 $55 =============================================================
Except as otherwise noted, the Company has contracted to operate and maintain all jointly owned facilities. The Company includes its proportionate share of plant operating expenses in the corresponding operating expenses in the Statements of Income.
As discussed in Note 4, the Company and OPC have a joint ownership arrangement for the Rocky Mountain pumped storage hydroelectric project under which the Company will retain its present investment in the project and OPC will
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finance and complete the remainder of the project and operate the completed facility. Based on current cost estimates the Company's ownership will be approximately 25 percent of the project (194 megawatts of capacity) at completion.
The Company will own six of eight 80 megawatt combustion turbine generating units and 75 percent of the related common facilities being jointly constructed at Plant McIntosh with Savannah Electric, an affiliate. The Company's investment in the project at December 31, 1994, was $149 million and is expected to total approximately $182 million when the project is completed. Four of the Company's six units began commercial operation during 1994, and the remaining two units are expected to be completed by June, 1995. Savannah Electric will operate these units.
In 1994, the Company and FPC entered into a joint ownership agreement regarding a 150 megawatt combustion turbine unit to be constructed near Orlando, Florida. The unit is scheduled to be in commercial operation in early 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.
In connection with the joint ownership arrangements for plants Vogtle and Scherer, the Company has made commitments to purchase declining fractions of OPC's and MEAG's capacity and energy from these units. 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 $129 million, $183 million and $289 million in 1994, 1993 and 1992, respectively. The Plant Scherer buyback agreements ended in 1993. The current projected Plant Vogtle capacity payments for the next five years are as follows: $77 million in 1995, $70 million in 1996, $59 million in 1997, $59 million in 1998, and $59 million in 1999. 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. Additionally, the Plant Vogtle declining capacity buyback expense is being levelized over a six-year period. See Note 3 for further information.
At December 31, 1994, 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 Unit 4 818 16.6 Plant McIntosh Common Facilities N/A 75.0 (combustion-turbine)
=================================================================
Accumulated Facility (Type) Investment Depreciation ----------------------------------------------------------------- (in millions) Plant Vogtle (nuclear) $3,289* $628 Plant Hatch (nuclear) 842 346 Plant Wansley (coal) 287 129 Plant Scherer (coal) Units 1 and 2 112 36 Unit 3 540 121 Unit 4 119 18 Plant McIntosh Common Facilities (combustion-turbine) 17 ** -----------------------------------------------------------------
* Investment net of write-offs. ** Less than $1 million.
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NOTES (continued) Georgia Power Company 1994 Annual Report
The Company and an affiliate, Alabama Power, 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:
============================================================ 1994 1993 1992 ------------------------------------------------------------ (in millions) Energy $43 $60 $47 Capacity 33 30 28 ------------------------------------------------------------ Total $76 $90 $75 ============================================================ Kilowatt-hours 2,429 3,352 2,664 ------------------------------------------------------------
At December 31, 1994, 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.
6. LONG-TERM POWER SALES AGREEMENTS
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 non-affiliated utilities located outside the system's service territory. These agreements consist of firm unit power sales pertaining to capacity from specific generating units and non-firm sales 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) 1994 $ 75 403 $ 9 101 1993 135 830 17 200 1992 223 1,363 10 124
Long-term non-firm power of 200 megawatts was sold by the Southern electric system in 1994 to FPC, of which the Company's share was 101 megawatts, under a contract that expired at year-end. Sales under these long-term non-firm power sales agreements are made from available power pool energy, and the revenues from the sales are shared by the operating affiliates.
Unit power from specific generating plants is being sold to FPL, JEA, and the City of Tallahassee, Florida and beginning in 1994 to FPC. Under these agreements, the Company sold approximately 403 megawatts of capacity in 1994 and is scheduled to sell approximately 248 megawatts of capacity in 1995. Thereafter, these sales will decline to an estimated 172 megawatts in 1996 then will remain at an approximate level of 158 megawatts through 1999. After 2000, capacity sales will decline to approximately 102 megawatts -- unless reduced by FPL, FPC, and JEA -- until the expiration of the contracts in 2010.
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NOTES (continued) Georgia Power Company 1994 Annual Report
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, 1994, the tax-related regulatory assets were $920 million and the tax-related regulatory liabilities were $433 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:
============================================================== 1994 1993 1992 --------------------------- Total provision for income taxes: (in millions) Federal: Currently payable $306 $223 $139 Deferred - Current year 86 181 170 Reversal of prior years (57) (40) (6) Deferred investment tax credits (1) (18) (6) -------------------------------------------------------------- 334 346 297 -------------------------------------------------------------- State: Currently payable 52 41 24 Deferred - Current year 15 31 35 Reversal of prior years (10) (3) (3) -------------------------------------------------------------- 57 69 56 -------------------------------------------------------------- Total 391 415 353 -------------------------------------------------------------- Less: Income taxes charged (credited) to other income (8) (37) (25) -------------------------------------------------------------- Federal and state income taxes charged to operations $399 $452 $378 ==============================================================
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax basis, which give rise to deferred tax assets and liabilities are as follows:
=============================================================== 1994 1993 ----------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,541 $1,458 Property basis differences 1,085 1,163 Deferred Plant Vogtle costs 141 161 Premium on reacquired debt 68 63 Deferred regulatory costs 48 24 Fuel clause underrecovered 9 32 Other 23 38 --------------------------------------------------------------- Total 2,915 2,939 --------------------------------------------------------------- Deferred tax assets: Other property basis differences 250 263 Federal effect of state deferred taxes 94 92 Other deferred costs 79 61 Disallowed Plant Vogtle buybacks 26 29 Accrued interest 10 24 Other 13 12 --------------------------------------------------------------- Total 472 481 --------------------------------------------------------------- Net deferred tax liabilities 2,443 2,458 Portion included in current assets 35 22 --------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $2,478 $2,480 ===============================================================
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 $25 million in 1994, $19 million in 1993, and $19 million in 1992. At December 31, 1994, all investment tax credits available to reduce federal income taxes payable had been utilized.
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NOTES (continued) Georgia Power Company 1994 Annual Report
A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
============================================================= 1994 1993 1992 ------------------------ Federal statutory rate 35% 35% 34% State income tax, net of federal deduction 4 4 4 Non-deductible book depreciation 3 3 3 Difference in prior years' deferred and current tax rate (1) (1) (1) Other - (1) (2) ------------------------------------------------------------- Effective income tax rate 41% 40% 38% =============================================================
The Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each company's current and deferred tax expense is computed on a stand-alone basis, and consolidated tax savings are allocated to each company based on its ratio of taxable income to total consolidated taxable income.
8. 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, 1994, $742 million of retained earnings 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, 1994, the ratio as defined was 47.3 percent.
Preferred Securities
Georgia Power Capital, a limited partnership, was formed November 10, 1994, for the purpose of issuing preferred securities and subsequently lending the proceeds to the Company. In December 1994, Georgia Power Capital issued four million shares of preferred securities at 9 percent and subsequently loaned the proceeds of $100 million to the Company. This subordinated debt of the Company is due December 19, 2024.
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 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 $651 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 1994 1993 ------------------------------------------------------------ (in millions) 2004 5.70% $ 39 $ 39 2005-2008 5.375% to 6.75% 59 59 2011-2014 11.75% & Variable 10 477 2015-2019 6.00% to 10.60% & Variable 786 830 2021-2024 5.40% to 7.25% & Variable 784 256 ------------------------------------------------------------ Total pollution control bonds $1,678 $1,661 ============================================================
Bank Credit Arrangements
At the beginning of 1995, the Company had unused credit arrangements with banks totaling $709 million, of which $268 million expires at various times during 1995, $41 million expires at May 1, 1997, and $400 million expires at June 30, 1997.
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NOTES (continued) Georgia Power Company 1994 Annual Report
The $400 million expiring June 30, 1997, is under revolving credit arrangements with several banks providing the Company, Alabama Power, and The Southern Company up to a total credit amount of $400 million. To provide liquidity support for commercial paper programs and for other short-term cash needs, $165 million and $135 million of the $400 million available credit are currently dedicated for the Company and Alabama Power, respectively. However, the allocations can be changed among the borrowers by notifying the respective banks.
During the term of the agreements expiring in 1997, 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 $709 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, 1994, is $219 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 1994.
Other Long-Term Debt
Assets acquired under capital leases are recorded in the Balance Sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 1994 and 1993, the Company had a capitalized lease obligation for its corporate headquarters building of $88 million with an interest rate of 8.1 percent. The maturity of this capital lease obligation through 1999 is approximately as follows: $310 thousand in 1995, $336 thousand in 1996, $365 thousand in 1997, $395 thousand in 1998, and $429 thousand in 1999.
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, 1994, and 1993, the interest and lease amortization deferred on the Balance Sheets are $48 million and $47 million, respectively.
In December 1993, the Company borrowed $37 million through a long-term note due in 1995.
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:
================================================================ 1994 1993 -------------- (in millions) First mortgage bond maturity $130 $ - Other long-term debt 37 11 ---------------------------------------------------------------- Total $167 $11 ================================================================
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 or reacquired bonds, or by pledging additional property equal to 1 2/3 times the requirement. The 1994 requirement was funded in December 1993. The 1995 requirement of $23 million
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NOTES (continued) Georgia Power Company 1994 Annual Report
will be satisfied 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.
9. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1994 and 1993 is as follows:
================================================================== Net Income After Dividends on Operating Operating Preferred Quarter Ended Revenues Income Stock ------------------------------------------------------------------ (in millions) March 1994 $ 992 $157 $ 58 June 1994 1,030 227 140 September 1994 1,213 331 233 December 1994 927 179 95
March 1993 $1,004 $221 $108 June 1993 1,096 219 141 September 1993 1,376 356 245 December 1993 975 176 76 ------------------------------------------------------------------
Earnings in 1994 declined by $55 million as a result of work force reduction programs. Of this amount, $52 million was recorded in the first quarter of 1994.
The Company's business is influenced by seasonal weather conditions.
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GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994
First Mortgage Bonds
Amount Interest Amount Series Issued Rate Outstanding Maturity ------------------------------------------------------------------- (Thousands) (Thousands) 1992 $ 130,000 5-1/8% $ 130,000 9/1/95 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 1989 250,000 9.23% 36,157 12/1/19 1992 100,000 8-3/4% 100,000 4/1/22 1992 100,000 8-5/8% 100,000 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 1992 100,000 Variable 100,000 4/1/32 1992 100,000 Variable 100,000 7/1/32 ---------- ---------- $2,360,000 $2,146,157 ========== ==========
Pollution Control Bonds
Amount Interest Amount Series Issued Rate Outstanding Maturity ------------------------------------------------------------------- (Thousands) (Thousands) 1992 $ 38,800 5.70% $ 38,800 9/1/04 1993 46,790 5-3/8% 46,790 3/1/05 1976 40,800 6-3/4% 1,940 11/1/06 1977 24,100 6.40% 1,960 6/1/07 1978 21,600 6-3/8% 8,130 4/1/08 1991 10,450 Variable 10,450 7/1/11 1985 150,000 10-1/8% 148,535 6/1/15 1985 200,000 10-1/2% 156,580 9/1/15 1985 100,000 10.60% 100,000 10/1/15 1985 100,000 10-1/2% 99,585 11/1/15 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 Variable 8,500 7/1/19 1991 51,345 7.25% 51,345 7/1/21 1991 10,125 Variable 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 Variable 10,000 12/1/24 1994 7,000 Variable 7,000 12/1/24 ---------- ---------- $1,797,910 $1,678,140 ========== ==========
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GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994 (Continued)
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 433,775 $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 ---------- -------- 21,027,865 $692,787 ========== ========
(1)Issued by Georgia Power Capital, L.P., and unconditionally guaranteed 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 1994
First Mortgage Bonds
Principal Interest Series Amount Rate ----------------------------------------------------- (Thousands) 1986 $ 69,716 10.00% 1989 63,843 9.23% -------- $133,559 ========
Pollution Control Bonds
Principal Interest Series Amount Rate ----------------------------------------------------- (Thousands) 1976 $ 20 6-3/4% 1977 20 6.40% 1978 70 6-3/8% 1984 28,065 11-5/8% 1984 113,745 12-1/4% 1984 123,175 11-5/8% 1984 126,735 12% 1984 75,070 11-3/4% 1985 43,420 10-1/2% -------- $510,320 ========
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GULF POWER COMPANY FINANCIAL SECTION
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MANAGEMENT'S REPORT Gulf Power Company 1994 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 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
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Gulf Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (a Maine corporation and a wholly owned subsidiary of The Southern Company) as of December 31, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective January 1, 1993, Gulf Power Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 15, 1995
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's net income after dividends on preferred stock for 1994 totaled $55.2 million, representing a $0.9 million increase from the prior year. Major factors affecting earnings were a decrease in interest charges on long-term debt as a result of security refinancings and an increase in customers. These positive factors were offset by lower revenues primarily due to mild summer weather, and an increase in other operation expenses and taxes. Also, earnings decreased approximately $3.0 million, reflecting the first full year of decreased industrial sales due to the Company's largest industrial customer, Monsanto, installing its own cogeneration facility in August, 1993. Earnings for 1994 increased from the 1993 level, even though 1993 earnings included $4.0 million of unusual items pertaining to the gain on sale of Gulf States Utilities Company (Gulf States) stock and the reversal of a wholesale rate refund discussed below.
In 1993, earnings were $54.3 million, representing a $0.2 million increase compared to the prior year. This increase resulted primarily from a $2.3 million gain on the sale of Gulf States' stock and the reversal of a $1.7 million wholesale rate refund as the result of a court order. The Company also experienced growth in residential and commercial sales and a decrease in interest expense on long-term debt as a result of security refinancings. These positive events were offset by higher operation and maintenance expense and decreased industrial sales, reflecting the loss of Monsanto, which is discussed above.
The Company's return on average common equity was 13.15 percent for 1994, a slight decrease from the 13.29 percent return earned in 1993.
Revenues
Changes in operating revenues over the last three years are the result of the following factors:
=========================================================== Increase (Decrease) From Prior Year ------------------------------- 1994 1993 1992 ------------------------------- (in thousands) Retail -- Change in base rates $ 0 $ 1,571 $ 722 Sales growth 7,126 7,671 12,965 Weather (4,631) 4,049 (6,448) Regulatory cost recovery and other 8,938 (3,079) (1,839) ----------------------------------------------------------- Total retail 11,433 10,212 5,400 ----------------------------------------------------------- Sales for resale-- Non-affiliates (6,098) 2,131* 442 Affiliates (5,813) (909) (5,268) ----------------------------------------------------------- Total sales for resale (11,911) 1,222 (4,826) ----------------------------------------------------------- Other operating revenues (3,851) 806 5,121 ----------------------------------------------------------- Total operating revenues $(4,329) $12,240 $ 5,695 =========================================================== Percent change (0.7)% 2.1% 1.0% -----------------------------------------------------------
* Includes the non-interest portion of the wholesale rate refund reversal discussed in "Earnings."
Retail revenues of $483.1 million in 1994 increased $11.4 million or 2.4 percent from last year, compared with an increase of 2.2 percent in 1993 and 1.2 percent in 1992. Revenues increased in the residential and commercial classes primarily due to customer growth and favorable economic conditions, partially offset by the effect of milder weather. Revenues in the industrial class declined in 1994 and 1993 primarily due to the loss of Monsanto as discussed in "Earnings." Also, in 1994, industrial sales decreased due to an unexpected six month plant shutdown -- which ended in October 1994 -- by another major industrial customer. The change in base rates for 1993 and 1992 reflects the expiration of a retail rate penalty in September 1992.
The increase in regulatory cost recovery and other retail revenue is primarily attributable to the first year of recovery under the Environmental Cost Recovery (ECR) clause. Regulatory cost recovery and other primarily includes recovery provisions for fuel expense and the energy component of purchased power costs; energy conservation costs; purchased power capacity
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1994 Annual Report
costs; and environmental compliance costs. The recovery provisions equal the related expenses and have no material effect on net income. See Notes 1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery," respectively, for further information.
Sales for resale were $83.5 million in 1994, decreasing $11.9 million or 12.5 percent from 1993. The majority of non-affiliated energy sales arise from long-term contractual agreements. Non-affiliated long-term contracts include capacity and energy components. Capacity revenues reflect the recovery of fixed costs and return on investment. Energy is sold at its variable cost. The capacity and energy components under these long-term contracts were as follows:
=========================================================== 1994 1993 1992 ------------------------------------ (in thousands) Capacity $30,926 $33,805 $34,180 Energy 18,456 21,202 22,933 ----------------------------------------------------------- $49,382 $55,007 $57,113 ===========================================================
Capacity revenues decreased in 1994, reflecting the 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 changes in other operating revenues for 1994 and 1993 are primarily due to adjustments of 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 1994 and percent changes in sales since 1992 are reported below.
============================================================= (millions of Amount Percent Change kilowatt-hours) ------ ---------------------- 1994 1994 1993 1992 ------ ---------------------- Residential 3,752 1.1% 3.2% 4.1% Commercial 2,549 4.8 2.7 4.2 Industrial 1,847 (9.0) (6.9) 2.9 Other 17 - - (2.7) ------ Total retail 8,165 (0.3) 0.4 3.8 Sales for resale Non-affiliates 1,419 (2.8) 2.0 (7.7) Affiliates 874 (15.2) (14.8) (2.2) ------ Total 10,458 (2.1) (1.1) 1.4 =============================================================
Retail sales decreased in 1994 primarily due to mild summer weather and a decline in sales in the industrial class, which reflects the loss of Monsanto and a lengthy shutdown of another major customer. The decline in sales was partially offset by a 2.4 percent increase in residential customers, a 2.9 percent increase in commercial customers, and an improving economy. Retail sales were relatively flat in 1993.
In 1994, energy sales for resale to non-affiliates decreased 2.8 percent and are predominantly related to unit power sales under long-term contracts to Florida utilities, which are discussed above. Energy sales to affiliated companies vary from year to year as mentioned previously.
Expenses
Total operating expenses for 1994 decreased $4.0 million or 0.8 percent from 1993. The decrease is primarily due to decreased fuel and purchased power expenses, offset by an increase in other operation expenses and taxes. In 1993, total operating expenses increased $16.6 million or 3.5 percent from 1992 primarily due to increased operation and maintenance expenses and higher taxes.
Fuel and purchased power expenses for 1994 declined $13.4 million or 6.5 percent from 1993. The decline reflects the decrease in generation due to the mild weather experienced in 1994 and the lower cost of fuel. In 1993, fuel and purchased power expenses decreased $3.8 million or 1.8 percent from 1992, reflecting the lower cost of fuel.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1994 Annual Report
In 1994, other operation expenses increased $4.7 million or 4.3 percent from the 1993 level. The increase is primarily attributable to additional costs of $6.4 million related to the buyouts and renegotiation of coal supply contracts and $1.3 million for the Company's pro rata share of affiliated companies' workforce reduction costs. These costs are further discussed in Notes 2 and 5 to the financial statements under "Work Force Reduction Programs" and "Fuel Commitments," respectively. The increase in coal buyouts and workforce reductions costs were partially offset by a decrease in various administrative and general expenses. In 1993, other operation expenses increased $11.9 million or 12.2 percent from the previous year, reflecting $7.4 million of additional costs related to the buyouts and renegotiation of coal supply contracts. In addition, in 1993, other operation expenses increased $3.5 million due to higher employee benefit costs, the Company's pro rata share of the Southern electric system's environmental cleanup costs of a research facility site, and costs related to an automotive fleet reduction program.
Maintenance expense remained relatively flat in 1994 reflecting no major changes in the scheduling of maintenance of production facilities. In 1993, maintenance expense increased $4.1 million or 9.7 percent over 1992 due to scheduled maintenance of production facilities.
Federal and state income taxes increased $1.2 million or 3.8 percent in 1994 primarily 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. In 1993, federal income taxes increased $0.7 million primarily due to a corporate federal income tax rate increase from 34 percent to 35 percent. Taxes other than income taxes increased $2.3 million in 1993, an increase of 6.1 percent over the 1992 expense primarily due to increases in property and gross receipt taxes. Changes in gross receipt taxes and franchise fee collections, which are collected from customers, have no impact on earnings.
In 1994, interest expense decreased $3.8 million or 10.5 percent under the prior year. Interest expense in 1993 decreased $3.2 million or 8.1 percent from the 1992 level. The decrease in both years is primarily attributable to the refinancing of 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.
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 a number of factors ranging from growth in energy sales to the effects of 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 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. 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 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 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. Presently, 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. In order to address these initiatives, numerous questions must be resolved, with the most complex ones
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1994 Annual Report
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 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 is the loss 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 Florida Public Service Commission (FPSC) has set conservation goals for the Company to reduce 148 megawatts of peak demand by the year 2003. The Company will file conservation programs in 1995 to accomplish these goals. 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.
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. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate schedules and power sales contracts that the Company has with its sales for resale customers. The FERC is currently reviewing the rate of return on common equity included in these schedules and contracts that have a return on common equity of 13.75 percent or greater, and may require such returns to be lowered, possibly retroactively. See Note 3 to the financial statements under "FERC Reviews Equity Returns" for additional information.
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."
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition during 1994 were gross property additions of $78.9 million and an increase of $47.4 million in notes payable. Funds for the property additions were provided by internal sources. The Company continued to refinance higher-cost securities to lower the Company's cost of capital. See "Financing Activities" below and the Statements of Cash Flows for further details.
Financing Activities
The Company continued to lower its financing costs by issuing new securities and other debt, and retiring higher-cost issues in 1994. The Company sold through public authorities, $42 million of pollution control revenue bonds and obtained $32.1 million of long-term bank notes. Retirements, including maturities during 1994, totaled $48.9 million of first mortgage bonds, $42.1 million of pollution control bonds, $24.2 million of bank notes and other long-term debt, and $1 million of preferred stock. (See the Statements of Cash Flows for further details.)
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1994 Annual Report
Composite financing rates for the years 1992 through 1994 as of year end were as follows:
=========================================================== 1994 1993 1992 ------------------------- Composite interest rate on long-term debt 6.5% 7.1% 8.0% Composite preferred stock dividend rate 6.6% 6.5% 7.3% ===========================================================
The continued decrease in the composite interest rate on long-term debt reflects the Company's continued efforts to refinance higher-cost debt, which is discussed above. The slight increase in the composite preferred dividend rate is primarily due to an increase in dividends on the Company's adjustable rate preferred stock, reflecting the recent rise in interest rates.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $222 million for the three years beginning 1995 ($62 million in 1995, $76 million in 1996, and $84 million in 1997). The estimates of property additions for the three-year period include $13 million committed to meeting the requirements of the Clean Air Act, the cost of which is expected to be recovered through the ECR clause, 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 the granting of timely and adequate rate increases; changes in environmental regulations; revised load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. The Company does not have any baseload generating plants under construction. However, significant construction related to maintaining and upgrading transmission and distribution facilities and generating plants will continue.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $74.3 million will be required by the end of 1997 in connection with maturities of long-term debt and preferred stock subject to mandatory redemption. 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 -- will have a significant impact on the Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants will be required in two phases. Phase I compliance began in 1995 and affects eight generating plants -- some 10,000 megawatts of capacity or 35 percent of total capacity -- in the Southern electric system. Phase II compliance is required by 2000, and all fossil-fired generating plants in the Southern electric system 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 rate-adjustment clause. 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 Environmental Cost Recovery clause.
In 1995, the Environmental Protection Agency (EPA) will begin 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 expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, which has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1994 Annual Report
expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment has been installed on all fossil-fired units. Construction expenditures for Phase I are estimated to total approximately $300 million for The Southern Company through 1995. Through 1994, the Company's construction expenditures for Phase I were approximately $51 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 anticipated Phase II limits. Therefore, during the period 1996 to 2000, the current compliance strategy could require total construction expenditures of approximately $150 million for The Southern Company, including approximately $19 million for the Company. However, the full impact of Phase II compliance cannot 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 4 percent in annual 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 by November 1995. 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 continues to evaluate the need for a new short-term ambient air quality standard for sulfur dioxide. Preliminary results from an EPA study on the impact of a new standard indicate that a number of plants could be required to install sulfur dioxide controls. These controls would be in addition to the controls already required to meet the acid rain provision of the Clean Air Act. The EPA issued proposed rules in November 1994 and is required to take final action on this issue in 1996. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality standards for particulate matter, nitrogen oxides, 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 1995, 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. For additional information, see Note 3 to the financial statements under "Environmental Cost Recovery."
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1994 Annual Report
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: 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 for lawsuits alleging damages caused by electromagnetic fields exists.
Sources of Capital
At December 31, 1994, the Company had $0.9 million of cash and cash equivalents to meet its short-term cash needs.
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 At December 31, 1994, 1993, and 1992 Gulf Power Company 1994 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) and The Southern Development and Investment Group (SDIG). 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, beginning in mid-1995, will provide digital wireless communications services -- over the 800-megahertz frequency band--to The Southern Company's subsidiaries and also will market these services to the public within the Southeast. Southern Electric designs, builds, owns and operates power production 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. SDIG 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.
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:
=========================================================== 1994 1993 ----------------------- (in thousands) Current & deferred fuel charges $ 40,690 $ 65,419 Deferred income taxes 30,433 31,334 Premium on reacquired debt 18,494 17,554 Environmental remediation 7,800 - Vacation pay 4,172 4,022 Regulatory clauses under (over) recovery, net 1,042 2,404 Deferred income tax credits (71,964) (76,876) Accumulated provision for property damage (11,522) (10,509) Other, net (2,691) (1,697) ----------------------------------------------------------- Total $ 16,454 $ 31,651 ===========================================================
In the event that a portion of the Company's operations are 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 to their fair value.
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NOTES (continued) Gulf Power Company 1994 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company accrues revenues for service rendered but unbilled at the end of each fiscal period. The Company's electric rates include provisions to periodically adjust billings for fluctuations in fuel and the energy component of purchased power costs; purchased power capacity costs; energy conservation costs; and environmental compliance costs. Revenues are adjusted monthly for differences between recoverable costs and amounts actually reflected in current rates.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates which approximated 3.8 percent in 1994, 1993, and 1992. 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.
Income Taxes
The Company 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.
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. Statement No. 109 required, among other things, conversion to the liability method of accounting for accumulated deferred income taxes. See Note 8 for additional information about Statement No. 109. The Company is included in the consolidated federal income tax return of The Southern Company.
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 1994 and the second half of 1993, and 8.03 percent for the first half of 1993 and all of 1992. AFUDC amounts for 1994, 1993, and 1992 were $1.1 million, $966 thousand, and $60 thousand, respectively. The increase in 1994 and 1993 is primarily due to an increase in construction projects at Plant Daniel.
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 1994 Annual Report
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Values of Financial Instruments, all financial instruments of the Company -- for which the carrying amount does not approximate fair value -- are shown in the table below as of December 31:
============================================================ ----------------------- Carrying Fair Amount Value ----------------------- (in thousands) Long-term debt $369,832 $355,019 Preferred stock subject to mandatory redemption 1,000 1,030 ============================================================
============================================================ ----------------------- Carrying Fair Amount Value ----------------------- (in thousands) Long-term debt $410,811 $431,251 Preferred stock subject to mandatory redemption 2,000 2,040 ============================================================
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.
Vacation Pay
The Company's employees earn their vacation in one year and take it in the subsequent year. However, for ratemaking purposes, vacation pay is recognized as an allowable expense only when paid. Consistent with this ratemaking treatment, the Company accrues a current liability for earned vacation pay and records a current asset representing the future recoverability of this cost. The amount was $4.2 million and $4.0 million at December 31, 1994, and 1993, respectively. In 1995, an estimated 81.3 percent of the 1994 deferred vacation cost will be expensed and the balance will be charged to construction and other accounts.
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 $2.5 million and $2.2 million at December 31, 1994, and 1993, respectively, is included in miscellaneous current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
Due to a significant increase in the cost of traditional insurance, effective in 1993, the Company became self-insured for the full cost of storm and other damage to its transmission and distribution property. As permitted by regulatory authorities, the Company provides for the estimated cost of uninsured property damage by charges to income amounting to $1.2 million annually. At December 31, 1994, and 1993, the accumulated provision for property damage amounted to $11.5 million and $10.5 million, respectively. The expense of repairing such damage as occurs from time to time is charged to the provision to the extent it is available.
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 "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 1994 Annual Report
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. A qualified trust for medical benefits is funded to the extent deductible under federal income tax regulations. Amounts funded are primarily invested in debt and equity securities.
Effective January 1, 1993, the Company adopted FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. Statement No. 106 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 costs of such benefits recognized by the Company in 1994 and 1993 were $4.3 million and $3.9 million, respectively.
Prior to 1993, the Company recognized these benefit costs on an accrual basis using the "aggregate cost" actuarial method, which spreads the expected cost of such benefits over the remaining periods of employees' service as a level percentage of payroll costs. The cost of such benefits recognized by the Company in 1992 was $3.1 million.
Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension and postretirement medical and life 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 ------------------------- 1994 1993 ------------------------- (in thousands) Actuarial present value of benefit obligation: Vested benefits $ 73,552 $ 73,925 Non-vested benefits 3,016 3,217 ----------------------------------------------------------------- Accumulated benefit obligation 76,568 77,142 Additional amounts related to projected salary increases 29,451 25,648 ----------------------------------------------------------------- Projected benefit obligation 106,019 102,790 Less: Fair value of plan assets 151,337 159,192 Unrecognized net gain (36,599) (49,376) Unrecognized prior service cost 2,802 3,152 Unrecognized transition asset (8,034) (8,765) ----------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 3,487 $ 1,413 =================================================================
================================================================= Postretirement Medical ------------------------- 1994 1993 ------------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $ 7,768 $ 7,857 Employees eligible to retire 4,043 4,054 Other employees 14,598 14,927 ----------------------------------------------------------------- Accumulated benefit obligation 26,409 26,838 Less: Fair value of plan assets 5,655 5,638 Unrecognized net loss (gain) 615 2,653 Unrecognized transition obligation 12,714 13,420 ----------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 7,425 $ 5,127 =================================================================
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NOTES (continued) Gulf Power Company 1994 Annual Report
================================================================= Postretirement Life -------------------- 1994 1993 -------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $3,032 $2,929 Employees eligible to retire - - Other employees 5,041 5,058 ----------------------------------------------------------------- Accumulated benefit obligation 8,073 7,987 Less: Fair value of plan assets 85 52 Unrecognized net loss (gain) (1,073) (641) Unrecognized transition obligation 2,806 2,954 ----------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $6,255 $5,622 =================================================================
The weighted average rates assumed in the actuarial calculations were:
================================================================= 1994 1993 1992 --------------------------- Discount 8.0% 7.5% 8.0% Annual salary increase 5.5% 5.0% 6.0% 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 10.5 percent for 1994, decreasing to 6.0 percent through the year 2000 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated medical benefit obligation at December 31,1994, by $4.8 million and the aggregate of the service and interest cost components of the net retiree medical cost by $660 thousand.
Components of the plans' net costs are shown below: ================================================================= Pension ----------------------------------- 1994 1993 1992 ----------------------------------- (in thousands) Benefits earned during the year $ 3,775 $ 3,710 $ 3,550 Interest cost on projected benefit obligation 7,484 7,319 6,939 Actual (return) loss on plan assets 3,721 (20,672) (6,431) Net amortization and deferral (17,054) 8,853 (4,054) ----------------------------------------------------------------- Net pension cost (income) $ (2,074) $ (790) $ 4 =================================================================
Of the above net pension amounts, pension expense/(income) of $(1.5) million in 1994, $(601) thousand in 1993, and $3 thousand in 1992, were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
================================================================= Postretirement Medical ----------------------- 1994 1993 ----------------------- (in thousands) Benefits earned during the year $1,092 $ 874 Interest cost on accumulated benefit obligation 1,952 1,714 Amortization of transition obligation 706 706 Actual (return) loss on plan assets 117 (726) Net amortization and deferral (575) 309 ----------------------------------------------------------------- Net postretirement cost $3,292 $2,877 =================================================================
================================================================= Postretirement Life ----------------------- 1994 1993 ----------------------- (in thousands) Benefits earned during the year $270 $ 292 Interest cost on accumulated benefit obligation 583 625 Amortization of transition obligation 148 148 Actual (return) loss on plan assets 12 (5) Net amortization and deferral (16) 1 ----------------------------------------------------------------- Net postretirement cost $997 $1,061 =================================================================
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NOTES (continued) Gulf Power Company 1994 Annual Report
Of the above net postretirement medical and life insurance amounts, $3.1 million in 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 has not had a work force reduction program but has incurred its pro rata share of affiliated companies' costs. The costs related to these programs were $1.3 million, $109 thousand, and $138 thousand for the years 1994, 1993, and 1992, 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 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 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 began in October 1994 and is scheduled to continue until January 1996.
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 $5.4 million at December 31, 1994. Although the final outcome of this matter cannot now be determined, in management's opinion, the final outcome will not result in changes that would have a material adverse effect on the Company's financial statements.
Environmental Cost Recovery
In April 1993, the Florida Legislature adopted legislation for an Environmental Cost Recovery (ECR) clause, 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 rate-adjustment clause. Such environmental costs include operation and maintenance expense, depreciation, and a return on invested capital.
On January 12, 1994, the FPSC approved the Company's initial petition under the ECR clause for recovery of environmental costs that were projected to be incurred from July 1993 through September 1994. After this initial period, recovery under the ECR clause is determined semi-annually and includes a true-up of the prior period and a projection of the ensuing six month period. During 1994 and 1993, the Company recorded $7.2 million and $2.6 million, respectively, of ECR revenues net of over/under recovery true-up amounts.
In 1994, the Company accrued a liability of $7.8 million for the estimated costs of environmental remediation projects for known sites. These estimated costs are expected to be expended during the period 1995 to 1999. These projects have been approved by the FPSC for recovery through the ECR clause discussed above. Therefore, the Company recorded $2.1 million in current assets and $5.7 million in deferred charges representing the future recoverability of these costs.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $62 million in 1995, $76 million in 1996, and $84 million in 1997. 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, 1994, significant purchase commitments were outstanding in connection with the construction program. The Company does not have any new
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NOTES (continued) Gulf Power Company 1994 Annual Report
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 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, 1994, the Company had $25 million in revolving credit lines subject to renewal June 1, 1997, and $22 million of lines of credit with banks subject to renewal June 1 of each year. In connection with these credit lines, the Company has agreed to pay certain fees and/or maintain compensating balances with the banks. The compensating balances, which represent substantially all the cash of the Company except for daily working funds and like items, are not legally restricted from withdrawal. The Company had $19 million of these lines of credit committed at December 31, 1994. In addition, the Company has bid-loan facilities with fourteen major money center banks that total $275 million, of which $34.5 million was committed at December 31, 1994.
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 were approximately $1.1 billion at December 31, 1994. Additional commitments will be required in the future to supply the Company's fuel needs.
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 ending in 1995. The remaining unamortized amount was $10.1 million at December 31, 1994.
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 $30.5 million at December 31, 1994.
Also, 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 and 1994, with a remainder of $118 thousand to be amortized to expense in the first quarter of 1995.
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.
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NOTES (continued) Gulf Power Company 1994 Annual Report
Lease Agreements
In 1989, the Company and Mississippi Power Company jointly entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars. In 1995, a second lease agreement for the use of 250 additional aluminum railcars will begin and continue 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 were $1.2 million in 1994, 1993, and 1992. For the year 1995, the Company's annual lease payments associated with both leases will be approximately $2.6 million. The Company's annual lease payments for 1996 through 1999 will be approximately $1.7 million and after 1999, lease payments total approximately $26.0 million. The Company has the option after three years from the date of the original contract on each lease to purchase the respective number of railcars at the greater of the termination value or the fair market value. Additionally, at the end of each lease term, the Company has the option to renew the lease.
6. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel, a steam-electric generating plant, located in Jackson County, Mississippi. In accordance with an operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of the plant.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3, 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, 1994, the Company's percentage ownership and its amount of 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 $185,339(1) $220,125 Accumulated Depreciation $45,814 $93,110 Construction Work in Progress $941 $1,163
Nameplate Capacity (2) (In 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
General
The Company and the other operating affiliates of The Southern Company 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:
================================================================ Other Unit Long- Year Power Term Total ---- ----------------------------------------- (in thousands) 1994 $29,653 $1,273 $30,926 1993 31,162 2,643 33,805 1992 32,679 1,501 34,180 ================================================================
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NOTES (continued) Gulf Power Company 1994 Annual Report
In 1994, long-term non-firm power of 200 megawatts was sold to Florida Power Corporation (FPC) under a contract that expired at year-end. Capacity and energy sales under these long-term non-firm power sales agreements were made from available power pool capacity, and the revenues from the sales were shared by the operating affiliates.
Unit power from specific generating plants is currently being sold to 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 1994, 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 $29.3 million in 1994, $39.5 million in 1993, and $46.2 million in 1992, or 5.1 percent, 6.8 percent, and 8.1 percent of operating revenues, respectively.
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, 1994, the tax-related regulatory assets to be recovered from customers were $30.4 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, 1994, the tax-related regulatory liabilities to be refunded to customers were $72.0 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
================================================================= 1994 1993 1992 ----------------------------- (in thousands) Total provision for income taxes: Federal-- Currently payable $34,941 $24,354 $24,287 Deferred--current year 18,556 26,396 18,173 --reversal of prior years (24,787) (22,102) (15,506) ----------------------------------------------------------------- 28,710 28,648 26,954 ----------------------------------------------------------------- State-- Currently payable 5,907 3,950 4,282 Deferred--current year 2,549 3,838 2,662 --reversal of prior years (3,304) (2,785) (2,007) ----------------------------------------------------------------- 5,152 5,003 4,937 ----------------------------------------------------------------- Total 33,862 33,651 31,891 Less income taxes charged (credited) to other income (95) 921 (187) ----------------------------------------------------------------- Federal and state income taxes charged to operations $33,957 $32,730 $32,078 =================================================================
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:
===================================================================== 1994 1993 ----------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $146,686 $146,657 Property basis differences 18,468 15,140 Coal contract buyout 6,896 15,427 Other 11,846 6,724 --------------------------------------------------------------------- Total 183,896 183,948 --------------------------------------------------------------------- Federal effect of state deferred taxes 9,732 10,136 Postretirement benefits 4,383 3,406 Property insurance 5,200 4,730 Other 7,566 6,500 --------------------------------------------------------------------- Total 26,881 24,772 --------------------------------------------------------------------- Net deferred tax liabilities 157,015 159,176 Portion included in current liabilities, net 5,334 7,433 --------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $151,681 $151,743 =====================================================================
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NOTES (continued) Gulf Power Company 1994 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 Statements of Income. Credits amortized in this manner amounted to $2.3 million in 1994, 1993 and 1992. At December 31, 1994, 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:
============================================================= 1994 1993 1992 -------------------------- Federal statutory rate 35% 35% 34% State income tax, net of federal deduction 4 3 4 Non-deductible book depreciation 1 1 1 Difference in prior years' deferred and current tax rate (2) (2) (2) Other (2) (1) (2) ------------------------------------------------------------- Effective income tax rate 36% 36% 35% =============================================================
The Company and the other subsidiaries of The Southern Company file a consolidated federal tax return. Under a joint consolidated income tax agreement, each company's current and deferred tax expense is computed on a stand-alone basis, and consolidated tax savings are allocated to each company based on its ratio of taxable income to total consolidated taxable income.
9. POLLUTION CONTROL OBLIGATIONS AND OTHER LONG-TERM DEBT
Details of long-term debt are as follows:
============================================================== December 31, 1994 1993 ---------------------- (in thousands) Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: Collateralized 6% due 2006* $ 12,200 $ 12,300 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 - Variable Rate Remarketed daily 20,000 - Non-collateralized 10.50% due 2014 - 42,000 -------------------------------------------------------------- $169,755 $169,855 -------------------------------------------------------------- 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 16,388 - 8.25% due 1995 - 17,520 -------------------------------------------------------------- 50,388 42,520 -------------------------------------------------------------- Total $220,143 $212,375 ==============================================================
* Sinking fund requirement applicable to the 6 percent pollution control bonds is $125 thousand for 1995 with increasing increments 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.
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NOTES (continued) Gulf Power Company 1994 Annual Report
The 5.39 percent and 5.72 percent notes payable are 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). These notes refinanced the remaining balance of the 8.25 percent note payable. The proceeds from the 6.44 percent note were used to refinance the remaining balance of the 9.2 percent first mortgage bond, which was redeemed in June, 1994. The estimated annual maturities of the notes payable through 1998 are as follows: $13.3 million in 1995, $29.6 million in 1996, $4.9 million in 1997, and $2.6 million in 1998.
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 is as follows:
============================================================== December 31 1994 1993 -------------------- (in thousands) Bond improvement fund requirement $ 1,750 $ 2,370 Less: Portion to be satisfied by cash or certifying property additions 1,750 - -------------------------------------------------------------- Cash sinking fund requirement - 2,370 Maturities of first mortgage bonds - 3,676 Redemptions of first mortgage bonds - 27,000 Current portion of notes payable 13,314 8,406 (Note 9) Pollution control bond maturity 125 100 (Note 9) -------------------------------------------------------------- Total $13,439 $41,552 ==============================================================
The first mortgage bond improvement (sinking) fund requirement amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to January 1 of each year, other than those issued to collateralize pollution control obligations. The requirement may be satisfied by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 and 2/3 times the requirement.
11. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's first mortgage bond indenture contains various common stock dividend restrictions which remain in effect as long as the bonds are outstanding. At December 31, 1994, $101 million of retained earnings was 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, 1994, the ratio was 47.2 percent.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1994 and 1993 are as follows:
================================================================= Net Income After Dividends Operating Operating on Preferred Quarter Ended Revenues Income Stock ----------------------------------------------------------------- (in thousands) 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
March 31, 1993 $127,036 $17,646 $10,426 June 30, 1993 138,863 19,562 7,312 Sept. 30, 1993 175,964 32,783 22,366 Dec. 31, 1993 141,279 22,596 14,207 =================================================================
The Company's business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.
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GULF POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994
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% 2,680 9/1/08 1991 50,000 8-3/4% 50,000 12/1/21 --------- -------- $ 175,000 $152,680 ========= ========
Pollution Control Bonds
Amount Interest Amount Series Issued Rate Outstanding Maturity ---------------------------------------------------------------- (Thousands) (Thousands) 1976 $ 12,500 6% $ 12,200 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 $169,755 ========= ========
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 1980 (1) 10,000 11.36% 1,000 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 --------- -------- 2,841,026 $ 90,602 ========= ======== (1) The outstanding balance of $1 million was redeemed on February 1, 1995.
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GULF POWER COMPANY
SECURITIES RETIRED DURING 1994
First Mortgage Bonds
Principal Interest Series Amount Rate ----------------------------------------------------- (Thousands) 1964 $12,000 4-5/8% 1966 15,000 6% 1978 2,370 9% 1988 19,486 9.20% ------- $48,856 =======
Pollution Control Bonds
Principal Interest Series Amount Rate ----------------------------------------------------- (Thousands) 1976 $ 100 6% 1984 42,000 10-1/2% ------- $42,100 =======
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 1994 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/ David M. Ratcliffe David M. Ratcliffe President and Chief Executive Officer
/s/ Michael W. Southern Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer
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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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective January 1, 1993, Mississippi Power changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
/S/ ARTHUR ANDERSEN LLP
Atlanta, Georgia February 15, 1995
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's net income after dividends on preferred stock for 1994 totaled $49.2 million, an increase of $6.7 million over the prior year. This improvement is attributable primarily to increased energy sales and rate increases. A retail rate increase under the Company's Performance Evaluation Plan (PEP) of $6.4 million annually became effective in July 1993. Under the Environmental Compliance Overview Plan (ECO Plan), retail rates increased by $7.6 million annually effective April 1994. Also, effective in April 1994 was a $3.6 million wholesale rate increase.
A comparison of 1993 to 1992 reflects an increase in 1993 earnings of $5.6 million. As was the case in 1994, earnings in 1993 increased because of higher energy sales and retail rate increases.
Revenues
The following table summarizes the factors impacting operating revenues for the past three years:
================================================================ Increase (Decrease) from Prior Year ----------------------------------- 1994 1993 1992 ----------------------------------- (in thousands) Retail -- Change in base rates $ 9,314* $ 5,079* $ 6,605 Sales growth 9,560 5,606 7,181 Weather 1,752 4,735 (3,915) Fuel cost recovery and other 6,594 15,028 (2,743) ---------------------------------------------------------------- Total retail 27,220 30,448 7,128 ---------------------------------------------------------------- Sales for resale -- Non-affiliates 4,611 3,298 1,387 Affiliates (5,981) 5,464 (7,989) ---------------------------------------------------------------- Total sales for resale (1,370) 8,762 (6,602) Other operating revenues (1,571) 1,226 1,535 ---------------------------------------------------------------- Total operating revenues $ 24,279 $ 40,436 $ 2,061 ================================================================ Percent change 5.1% 9.3% 0.5% ----------------------------------------------------------------
*Includes the effect of the retail rate increases approved under the ECO Plan.
Retail revenues of $395 million in 1994 increased 7.4 percent over the prior year, compared with increases of 9.0 percent and 2.2 percent in 1993 and 1992, respectively. The increase in retail revenues for 1994 was a result of growth in energy sales and customers and retail rate increases. Changes in base rates reflect rate changes made under PEP and the ECO Plan as approved by the Mississippi Public Service Commission (MPSC).
Under the fuel cost recovery provision, recorded fuel revenues are equal to recorded fuel expenses, including the fuel component and the operation and maintenance component of purchased energy. Therefore, changes in recoverable fuel expenses are offset with corresponding changes in fuel revenues and have no effect on net income.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1994 Annual Report
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 7.8 percent in 1994 and 9.0 percent in 1993 with the related revenues rising 14.0 percent and 14.1 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to Mississippi Power's.
Sales for resale to non-affiliated 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:
============================================================= 1994 1993 1992 ---------------------------------------- (in thousands) Capacity $ 1,965 $ 4,191 $ 3,573 Energy 8,473 12,120 19,538 ------------------------------------------------------------- Total $10,438 $16,311 $23,111 =============================================================
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 1994 and the percent change for the last three years:
================================================================== Amount Percent Change (millions of -------- ----------------------------- kilowatt-hours 1994 1994 1993 1992 -------- -----------------------------
Residential 1,922 (0.4)% 6.9 % (1.5)% Commercial 2,101 8.6 6.8 2.4 Industrial 3,847 6.2 2.5 7.3 Other 38 (0.5) 0.3 (57.2) ----- Total retail 7,908 5.1 4.7 2.9 Sales for resale -- Non-affiliates 2,556 0.4 (5.3) (0.7) Affiliates 174 (59.2) 52.2 (54.6) ------ Total 10,638 1.3% 3.3% (1.5)% ==================================================================
Total retail energy sales in 1994 increased, compared to the previous year, due primarily to the improvement in the economy. The most notable factor that increased commercial energy sales was the recent establishment of casinos within the Company's service area. It is expected that the establishment of new casinos should slow appreciably. However, growth in ancillary services (lodging, food, transportation, etc.) should continue. Also, energy demand is expected to grow as a result of a larger and more fully employed population. The improvement in the economy also carried over to the industrial sector. Retail energy sales in 1993 increased due to an improving economy and weather influences. Industrial sales increased in 1992 as a result of new contracts with two large industrial customers.
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 1994 were higher than the previous year because of higher taxes and an increase in maintenance expenses and depreciation and amortization. Additionally, included in other operation expenses are increased costs associated with work force reduction programs. (See Note 2 to the financial statements for information on these programs.) Expenses in 1993 were higher than 1992 primarily because of higher production expenses stemming from
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1994 Annual Report
increased demand, an increase in the federal income tax rate, and higher employee related costs.
Fuel costs constitute the single largest expense for Mississippi Power. These costs decreased in 1994 due to a 5.5 percent decrease in generation, which reflects lower demand on the rest of the Southern electric system and, hence, the availability of lower cost generation from affiliates. Fuel expenses in 1993, compared to 1992, were higher because of increased generation reflecting higher 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 increase in depreciation and amortization is primarily the result of the commercial operation of a 75 megawatt combustion turbine unit in May 1994.
Taxes other than income taxes increased in 1994 because of higher ad valorem taxes, which are property based, and municipal franchise taxes, which are revenue based.
The change in income taxes for 1994 reflected the change in operating income. Income tax expense in 1993 increased because of the enactment of a higher corporate income tax rate retroactive to January 1, 1993, coupled with higher earnings.
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 growth in energy sales to a less regulated, more competitive environment. Expenses are subject to constant review and cost control programs. Among the efforts to control costs are utilizing employees more effectively through a functionalization program for the Southern electric system, redesigning compensation and benefit packages, and re-engineering work processes. Mississippi Power is also maximizing the utility of invested capital and minimizing the need for capital by refinancing, decreasing the average fuel stockpile, raising generating plant availability and efficiency, and managing the construction budget. Operating revenues will be affected by any changes in rates under the PEP, the Company's performance based ratemaking plan. PEP has proven to be a stabilizing force on electric rates, with only moderate changes in rates taking place.
The ECO Plan, approved by the MPSC in 1992, provides for recovery of costs associated with environmental projects approved by the MPSC, most of which are required to comply with Clean Air Act Amendments of 1990 (Clean Air Act) regulations. The ECO Plan is operated independently of PEP. 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1994 Annual Report
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 changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, weather, competition, 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. See Note 1 to the financial statements under "Regulatory Assets and Liabilities," for additional information.
FINANCIAL CONDITION
Overview
The principal changes in Mississippi Power's financial condition during 1994 were gross property additions to utility plant of $104 million, including the commercial operation of a 75 megawatt capacity combustion turbine unit. Funding for gross property additions and other capital requirements came primarily from capital contributions from The Southern Company, the sale of first mortgage bonds, the issuance of long-term notes payable, earnings and other operating cash flows. The Statements of Cash Flows provide additional details.
Financing Activity
Mississippi Power continued to lower its financing costs in 1994 by issuing new debt securities and retiring high-cost issues. The Company sold $35 million of first mortgage bonds and issued $85 million in term notes. Retirements, including maturities during 1994, totaled some $42 million of such securities. (See the Statements of Cash Flows for further details.) Composite financing rates for the years 1992 through 1994 as of year-end were as follows:
=========================================================== 1994 1993 1992 --------------------------- Composite interest rate on long-term debt 6.44% 6.57% 6.91%
Composite preferred stock dividend rate 6.58% 6.58% 7.29%
===========================================================
Capital Structure
At year-end 1994, the Company's ratio of common equity to total capitalization was 48.7 percent, compared to 49.8 percent in 1993 and 47.3 percent in 1992. The lower equity ratio in 1994 can be attributed primarily to additional long-term debt.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $223 million ($78 million in 1995, $73 million in 1996, and $72 million in 1997). The major emphasis within the construction program will be on upgrading existing facilities. Also included in the estimates for property additions for
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1994 Annual Report
the three-year period is $2.9 million committed to meeting the requirements of Clean Air Act regulations. Revisions may be necessary because of factors such as 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 $96 million will be required by the end of 1997 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 -- will have a significant impact on 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 will be required in two phases. Phase I compliance began in 1995 and affects eight generating plants -- some 10 thousand megawatts of capacity or 35 percent of total capacity -- in the Southern electric system. 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 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 expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, which has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures were required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment will be installed on all fossil-fired units. Under this Phase I compliance approach, additional construction expenditures are estimated to total approximately $300 million through 1995 for The Southern Company, of which Mississippi Power's portion is 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 anticipated Phase II limits. Therefore, during the period 1996 to 2000, current compliance strategy for The Southern Company could require total 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1994 Annual Report
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.
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 by November 1995. 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 continues to evaluate the need for a new short-term ambient air quality standard for sulfur dioxide. Preliminary results from an EPA study on the impact of a new standard indicate that a number of plants could be required to install sulfur dioxide controls. These controls would be in addition to the controls already required to meet the acid rain provisions of the Clean Air Act. The EPA issued proposed rules in November 1994 and is required to take final action on this issue in 1996. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality standards for particulate matter, nitrogen oxides, 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 1995, 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 is under investigation for potential remediation, but no prediction can presently be made regarding the extent, if any, of contamination or possible cleanup. Results of this investigation are expected to be available in early 1995. 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. Accordingly, no accrual has been made for remediation in the accompanying financial statements.
Several major pieces of environmental legislation are in the process of being reauthorized or amended by Congress. These include: the Clean Water Act; the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability 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 for lawsuits alleging damages caused by electromagnetic fields exists.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1994 Annual Report
Sources of Capital
At December 31, 1994, 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 1994.
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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STATEMENTS OF INCOME For the Years Ended December 31, 1994, 1993, and 1992 Mississippi Power Company 1994 Annual Report
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STATEMENTS OF CASH FLOWS For the Years ended December 31, 1994, 1993, and 1992 Mississippi Power Company 1994 Annual Report
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BALANCE SHEETS At December 31, 1994 and 1993 Mississippi Power Company 1994 Annual Report
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BALANCE SHEETS At December 31, 1994 and 1993 Mississippi Power Company 1994 Annual Report
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STATEMENTS OF CAPITALIZATION At December 31, 1994 and 1993 Mississippi Power Company 1994 Annual Report
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STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1994, 1993, and 1992 Mississippi Power Company 1994 Annual Report
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NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 1994 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 (SDIG). 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, beginning in mid-1995, will provide digital wireless communications services--over the 800-megahertz frequency band--to The Southern Company's subsidiaries and also will market these services to the public within the Southeast. Southern Electric designs, builds, owns, and operates power production 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. SDIG 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.
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)
=============================================================== 1994 1993 ------------------------ Deferred income taxes $25,036 $25,267 Vacation pay 4,588 4,797 Work force reduction costs 11,286 - Deferred fuel charges 10,068 17,960 Premium on reacquired debt 9,571 10,563 Property damage reserve (10,905) (10,538) Deferred income tax credits (45,832) (48,228) Other, net (3,383) (3,653) --------------------------------------------------------------- Total $ 429 $(3,832) ===============================================================
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 write down the assets to their fair value.
Revenues
Mississippi Power accrues revenues for service rendered but unbilled at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel and the energy component of purchased power. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental
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NOTES (continued) Mississippi Power Company 1994 Annual Report
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 comprised 10 percent or more of revenues. In 1994, 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 1994, 3.1 percent in 1993, and 3.3 percent in 1992. 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.
Income Taxes
Mississippi Power 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.
Effective January 1, 1993, Mississippi Power adopted FASB Statement No. 109, Accounting for Income Taxes. Statement No. 109 required, among other things, conversion to the liability method of accounting for accumulated deferred income taxes. See Note 8 to the financial statements for additional information about Statement No. 109.
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 6.9 percent in 1994, 6.8 percent in 1993, and 8.2 percent in 1992. AFUDC (net of income taxes), as a percent of net income after dividends on preferred stock, was 3.5 percent in 1994 and 1993 and 2.7 percent in 1992.
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, 1994, the fair value of long-term debt was $331 million and the carrying amount was $348 million. At December 31, 1993, the fair value of long-term debt was $278 million and the carrying amount was $270 million. The fair value for long-term debt was based on either closing market price or closing price of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when used or installed.
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NOTES (continued) Mississippi Power Company 1994 Annual Report
Vacation Pay
Mississippi Power's employees earn their vacation in one year and take it in the subsequent year. However, for ratemaking purposes, vacation pay is recognized as an allowable expense only when paid. Consistent with this ratemaking treatment, the Company accrues a current liability for earned vacation pay and records a current asset representing the future recoverability of this cost. Such amounts were $4.6 million and $4.8 million at December 31, 1994 and 1993, respectively. In 1995, an estimated 78 percent of the 1994 deferred vacation cost will be expensed, and the balance will be charged to construction and other accounts.
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 $1.1 million in 1994 and $1.5 million in 1993 and 1992. 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. As of December 31, 1994, the accumulated provision amounted to $10.9 million, the maximum allowed for 1994. Effective January 1995, regulatory treatment by the MPSC allows a maximum accumulated provision of $18 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 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 "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. Qualified trusts are funded to the extent required by the Company's regulatory commissions. Amounts funded are primarily invested in debt and equity securities.
Effective January 1, 1993, Mississippi Power adopted FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. Statement No. 106 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.
Prior to 1993, Mississippi Power recognized these benefit costs on an accrual basis using the "aggregate cost" actuarial method, which spreads the expected cost of such benefits over the remaining periods of employees' service as a level percentage of payroll costs. The total cost of such benefits recognized by the Company was $3.6 million in 1992.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension and postretirement medical and life 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:
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NOTES (continued) Mississippi Power Company 1994 Annual Report
=============================================================== Pension ------------------- 1994 1993 ------------------- (in thousands) Actuarial present value of benefit obligation: Vested benefits $80,603 $73,735 Non-vested benefits 2,966 3,245 -------------------------------------------------------------- Accumulated benefit obligation 83,569 76,980 Additional amounts related to projected salary increases 27,292 24,434 --------------------------------------------------------------- Projected benefit obligation 110,861 101,414 Less: Fair value of plan assets 145,598 154,224 Unrecognized net gain (37,485) (49,239) Unrecognized prior service cost 3,109 3,590 Unrecognized transition asset (6,635) (7,188) --------------------------------------------------------------- Prepaid asset (accrued liability) recognized in the Balance Sheets $(6,274) $ (27) ===============================================================
Postretirement Medical ------------------------ 1994 1993 ------------------------ (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $18,106 $10,408 Employees eligible to retire 774 3,752 Other employees 19,124 19,389 --------------------------------------------------------------- Accumulated benefit obligation 38,004 33,549
Less: Fair value of plan assets 6,460 6,271 Unrecognized net loss (gain) 2,301 3,500 Unrecognized transition obligation 15,319 16,540 --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $13,924 $ 7,238 ===============================================================
Postretirement Life ---------------------- 1994 1993 ---------------------- (in thousands) Actuarial present value of benefit obligation: Retirees $4,727 $3,315 Other employees 3,727 4,596 ----------------------------------------------------------- Accumulated benefit obligation 8,454 7,911 Less: Fair value of plan assets 148 84 Unrecognized net loss (gain) (550) (632) Unrecognized transition obligation 3,349 3,606 ----------------------------------------------------------- Accrued liability recognized in the Balance Sheets $5,507 $4,853 ===========================================================
The weighted average rates assumed in the above actuarial calculations were:
========================================================== 1994 1993 1992 ---------------------------- Discount 8.0% 7.5% 8.0% Annual salary increase 5.5 5.0 6.0 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 10.5 percent for 1994 decreasing gradually to 6.0 percent through the year 2000 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated medical benefit obligation as of December 31, 1994, by $6.7 million and the aggregate of the service and interest cost components of the net retiree medical cost by $1.1 million.
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NOTES (continued) Mississippi Power Company 1994 Annual Report
Components of the plans' net cost are shown below:
================================================================ Pension ------------------------------ 1994 1993 1992 ------------------------------ (in thousands) Benefits earned during the year $ 3,780 $ 3,792 $ 3,595 Interest cost on projected benefit obligation 7,503 7,296 6,886 Actual (return) loss on plan assets 3,244 (20,017) (5,812) Net amortization and deferral (16,048) 8,741 (4,265) ---------------------------------------------------------------- Net pension cost (income) $(1,521) $ (188) $ 404 ================================================================
Of the above net pension amounts recorded, $(1.1) million in 1994, $(170) thousand in 1993, and $269 thousand in 1992, and were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Postretirement Medical --------------------------- 1994 1993 --------------------------- (in thousands) Benefits earned during the year $1,486 $1,149 Interest cost on accumulated benefit obligation 2,666 2,187 Amortization of transition obligation over 20 years 864 871 Actual (return) loss on plan assets 127 (808) Net amortization and deferral (562) 343 ---------------------------------------------------------------- Net postretirement cost $4,581 $3,742 ================================================================
Postretirement Life --------------------- 1994 1993 --------------------- (in thousands) Benefits earned during the year $ 274 $ 299 Interest cost on accumulated benefit obligation 585 624 Amortization of transition obligation over 20 years 179 180 Actual (return) loss on plan assets 5 (6) Net amortization and deferral (13) - --------------------------------------------------------------- Net postretirement cost $1,030 $1,097 ===============================================================
Of the above net postretirement medical and life insurance costs recorded, $4.4 million in 1994 and $3.9 million in 1993 was charged to operating expense and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
During 1994, Mississippi Power and SCS instituted work force reduction programs. The costs of the SCS work force reduction program were apportioned among the various entities that form the Southern electric system, with the Company's portion amounting to $1.4 million. The Company instituted an early retirement incentive program in April 1994 and deferred the related costs of approximately $12.9 million. The Company received authority from the MPSC to defer these costs, as well as its portion of the costs of the SCS program, and to amortize over a period not to exceed 60 months, beginning no later than January 1995. During 1994, the Company expensed $3.0 million of the cost of these programs.
3. LITIGATION AND REGULATORY MATTERS:
Retail Rate Adjustment Plans
Mississippi Power's retail base rates are set under a Performance Evaluation Plan (PEP). The current version, PEP-2 was approved by the MPSC in January 1994. 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 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 1994, there was no increase under PEP-2.
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. 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 a $7.6 million increase effective April 1994. On
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NOTES (continued) Mississippi Power Company 1994 Annual Report
January 31, 1995, the Company filed the ECO Plan with the MPSC requesting an annual retail rate increase of $3.7 million, which included $1.6 million of 1994 carryover.
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. See "Environmental Matters" in the Management's Discussion and Analysis for information on a manufactured gas plant site.
FERC Reviews 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 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 changes 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 began in October 1994 and is scheduled to continue until January 1996.
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 $0.6 million at December 31, 1994. Although the final outcome of this matter cannot now be determined, in management's opinion, the final outcome will not result in changes that would have a material adverse effect on the Company's financial statements.
4. CONSTRUCTION PROGRAM:
Mississippi Power is engaged in continuous construction programs, the costs of which are currently estimated to total some $78 million in 1995, $73 million in 1996, and $72 million in 1997. These estimates include AFUDC of $1.7 million in 1995, $2.2 million in 1996, and $1.5 million in 1997.
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.
See "Environmental Matters" in Management's Discussion and Analysis for information on the impact of the Clean Air Act Amendments of 1990 and other environmental matters.
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. See "Sources of Capital" in Management's Discussion and Analysis for information regarding the Company's coverage requirements.
At December 31, 1994, 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
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NOTES (continued) Mississippi Power Company 1994 Annual Report
agreements expiring at various dates during 1995 and in 1997. The agreements expiring December 31, 1997, 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 1994.
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 1994 use fees collected under this agreement, net of related expenses, amounted to $3.9 million each year, and are included with other income, net, in the Statements of Income. For other 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 $1.2 million in each of the past three years. For the year 1995, the Company's annual lease payment will be $2.6 million, of which $1.2 million was charged to inventory in 1994. Lease payments will be approximately $1.7 million per year for the years 1996 through 1999. Lease payments after 1999 total approximately $26.1 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 $393 million at December 31, 1994. 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 through 1995 to match costs with savings achieved. The remaining unamortized amount of Mississippi Power's share of principal payments to the suppliers totaled $10.1 million at December 31, 1994.
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, 1994, 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% $ 57,567 $29,742
Daniel 1,000 50% 219,870 90,908 --------------------------------------------------------------------------
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NOTES (continued) Mississippi Power Company 1994 Annual Report
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 entered into long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside of 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) 1994 $ 660 $1,305 $1,965 1993 1,571 2,620 4,191 1992 2,168 1,405 3,573 ------------------------------------------------------------
In 1994, long-term non-firm power of 200 megawatts was sold by the Southern electric system to Florida Power Corporation 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, 1994, the tax-related regulatory assets to be recovered from customers were $25 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, 1994, the tax-related regulatory liabilities to be refunded to customers were $46 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and unamortized investment tax credits.
Details of the federal and state income tax provisions are shown below:
================================================================== 1994 1993 1992 ------------------------------ (in thousands) Total provision for income taxes Federal -- Currently payable $26,072 $15,842 $20,286 Deferred --current year 6,313 5,158 (1,578) --reversal of prior years (5,161) (820) (3,931) ------------------------------------------------------------------ 27,224 20,180 14,777 ------------------------------------------------------------------ State -- Currently payable 3,978 2,945 2,992 Deferred --current 1,669 1,339 218 --reversal of prior years (1,258) (638) (182) ------------------------------------------------------------------ 4,389 3,646 3,028 ------------------------------------------------------------------ Total 31,613 23,826 17,805 Less income taxes charged to other income 227 1,158 1,427 ------------------------------------------------------------------ Federal and state income taxes charged to operations $31,386 $22,668 $16,378 ==================================================================
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax
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NOTES (continued) Mississippi Power Company 1994 Annual Report
bases, which give rise to deferred tax assets and liabilities are as follows:
=============================================================== 1994 1993 ------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $138,281 $130,299 Basis differences 11,645 11,332 Coal contract buyouts 3,851 6,870 Other 17,908 18,719 --------------------------------------------------------------- Total 171,685 167,220 --------------------------------------------------------------- Deferred tax assets: Other property basis differences 27,375 28,779 Pension and other benefits 5,386 4,625 Property insurance 4,171 4,031 Unbilled fuel 3,649 4,205 Other 7,009 5,562 -------------------------------------------------------------- Total 47,590 47,202 -------------------------------------------------------------- Net deferred tax liabilities 124,095 120,018 Portion included in current assets, net 5,410 4,316 -------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $129,505 $124,334 ==============================================================
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 both 1994 and 1993 and $1.4 million in 1992. At December 31, 1994, 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:
============================================================= 1994 1993 1992 ---------------------------- Total effective tax rate 37% 33% 30% State income tax, net of federal income tax benefit (3)% (3) (3) Tax rate differential 1 4 6 Other - 1 1 ------------------------------------------------------------- Statutory federal tax rate 35% 35% 34% =============================================================
Mississippi Power and its affiliates file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each company's current and deferred tax expense is computed on a stand-alone basis, and consolidated tax savings are allocated to each company based on its 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, 1994 1993 ------------------- (in thousands) Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds: 5.80% due 2007 $ 980 $ 990 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 -------------------------------------------------------------- 63,155 63,165 -------------------------------------------------------------- Notes payable: 8.25% due 1994-1995 - 17,520 7.50% due 1994-1995 1,689 2,158 5.39% to 5.72% due 1995 9,000 - 4.15% to 5.89% due 1995-1996 50,000 - 6.0375% due 1996 35,000 - -------------------------------------------------------------- 95,689 19,678 -------------------------------------------------------------- Total $158,844 $82,843 ==============================================================
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
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NOTES (continued) Mississippi Power Company 1994 Annual Report
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 and 1999.
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:
=============================================================== 1994 1993 ------------------- (in thousands) Bond improvement fund requirements $ 1,931 $ 1,902
Less: Portion to be satisfied by certifying property additions 1,431 1,402 --------------------------------------------------------------- Cash improvement fund requirements 500 500 First mortgage bond maturities and redemptions - 10,000 Pollution control bond cash sinking fund requirements (Note 9) 10 10 Current portion of notes payable (Note 9) 40,689 8,835 --------------------------------------------------------------- Total $41,199 $19,345 ===============================================================
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, 1994, $94 million of retained earnings was restricted against the payment of cash dividends on common stock under the most restrictive terms of the mortgage indenture or corporate charter.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial data for 1994 and 1993 are as follows:
=================================================================== Net Income After Dividends Quarter Operating Operating On Ended Revenues Income Preferred Stock ------- ------------------------------------------------
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
March 1993 $101,552 $ 9,529 $ 4,424 June 1993 117,764 18,147 11,852 September 1993 148,102 22,377 16,560 December 1993 107,465 13,333 9,600
Mississippi Power's business is influenced by seasonal weather conditions and the timing of rate changes.
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SELECTED FINANCIAL AND OPERATING DATA Mississippi Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Mississippi Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Mississippi Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Mississippi Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Mississippi Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Mississippi Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Mississippi Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Mississippi Power Company 1994 Annual Report
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STATEMENTS OF INCOME Mississippi Power Company
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STATEMENTS OF INCOME Mississippi Power Company
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STATEMENTS OF INCOME Mississippi Power Company
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STATEMENTS OF CASH FLOWS Mississippi Power Company
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STATEMENTS OF CASH FLOWS Mississippi Power Company
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STATEMENTS OF CASH FLOWS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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BALANCE SHEETS Mississippi Power Company
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MISSISSIPPI POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1994
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% 47,072 5/1/21 1993 35,000 7.45% 35,000 6/1/23 -------- -------- $195,000 $192,072 ======== ========
Pollution Control Bonds
Amount Interest Amount Series Issued Rate Outstanding Maturity ---------------------------------------------------------------- (Thousands) (Thousands) 1977 $ 1,000 5.80% $ 980 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 -------- -------- $ 63,175 $ 63,155 ======== ========
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 1994
First Mortgage Bonds
Principal Interest Series Amount Rate ----------------------------------------------------------------------------- (Thousands) 1964 $10,000 4-5/8% 1965 11,000 4-3/4% 1966 10,000 6% 1991 1,628 9-1/4% ------- $32,628 =======
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 1994 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
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS Savannah Electric and Power Company 1994 Annual Report
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, 1994 and 1993, 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, 1994. 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-246) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for the periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective January 1, 1993, the Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 15, 1995
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 1994 totaled $22.1 million, representing a $0.6 million (3.0 percent) increase over the prior year. This increase was primarily due to a decrease in operating expenses, offset somewhat by an increase in interest expense.
In 1993, earnings were $21.5 million, representing a $1.0 million (4.6 percent) increase from the prior year. The revenue impact of an increase in retail energy sales due to exceptionally hot summer weather was partially offset by the implementation of a work force reduction program which resulted in a one-time charge to operating expenses of approximately $4.5 million.
Revenues
Total revenues for 1994 were $211.8 million, reflecting a 3.0 percent decrease compared to 1993. The revenue impact of an expanding customer base was offset by moderate weather, reduced industrial energy sales, and an associated decrease in fuel cost recovery revenues.
The following table summarizes revenue increases and decreases compared to prior years:
============================================================== Increase (Decrease) From Prior Years -------------------------------- 1994 1993 1992 -------------------------------- Retail -- (in thousands) Change in base rates $ - $(1,450) $(1,350) Sales growth 7,884 5,980 5,467 Weather (6,589) 4,567 (3,116) Fuel cost recovery and other (9,214) 12,404 7,270 -------------------------------------------------------------- Total retail (7,919) 21,501 8,271 -------------------------------------------------------------- Sales for resale-- Non-affiliates (1,235) (1,800) 8 Affiliates 4,013 928 75 -------------------------------------------------------------- Total sales for resale 2,778 (872) 83 -------------------------------------------------------------- Other operating revenues (1,516) 52 (239) -------------------------------------------------------------- Total operating revenues $(6,657) $20,681 $ 8,115 ============================================================== Percent change (3.0)% 10.5% 4.3% --------------------------------------------------------------
Retail revenues decreased 3.8 percent in 1994, compared to an increase of 11.5 percent in 1993. The decrease in 1994 retail revenues is attributable to milder summer weather, reduced industrial energy sales, and substantially lower fuel cost recovery revenues, offset somewhat by customer growth. Industrial energ y sales turned down in the fourth quarter of 1994 when operations of a large industrial customer were temporarily curtailed due to a mechanical failure of a machine which was a major part of the customer's manufacturing operation. Under the Company's fuel cost recovery provisions, fuel revenues --including purchased energy-- generally equal fuel expense and have no effect on earnings. The $1.5 million decrease in other operating revenues reflects deferral of over recovery of demand-side management rider revenues during 1994. Revenues from demand-side management riders (included in retail revenues) recover demand-side management program costs and have little impact on earnings.
The increase in 1993 retail revenues resulted from customer growth and an increase in the average annual kilowatt-hour use per customer which was substantially increased due to hot summer weather.
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 decreased in 1994 due to reductions in sales to Florida Power Corporation. The capacity and energy components were as follows:
========================================================
1994 1993 1992 -------------------------------------------------------- (in thousands) Capacity $ 448 $ 978 $ 537 Energy 3,052 4,262 7,040 -------------------------------------------------------- Total $3,500 $5,240 $7,577 ========================================================
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 1994 Annual Report
Kilowatt-hour sales for 1994 and the percent change by year were as follows:
=============================================================== Percent Change ------------------------- KWH 1994 1993 1992 ---------- ------------------------ (in millions) Residential 1,298 (2.3)% 9.2% 1.8% Commercial 1,046 2.9 6.5 3.0 Industrial 800 (6.4) (0.8) 4.3 Other 119 3.1 5.2 3.4 ------ Total retail 3,263 (1.6) 5.5 2.9 Sales for resale - Non-affiliates 202 (18.4) (32.7) (1.3) Affiliates 93 23.4 100.3 15.5 ------ Total 3,558 (2.2)% 2.6% 2.6% ====== ===============================================================
Expenses
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, principally two combustion turbine units. Interest expense increased $1.9 million primarily due to the sale in June 1993 of $45 million of first mortgage bonds.
Total operating expenses for 1993 increased $20.3 million (12.4 percent) over the prior year. This increase includes a $10.8 million increase in fuel expense, and an $8.7 million increase in other operation expenses. Fuel expenses increased primarily because of higher generation due to extremely hot summer weather and the higher cost of fuel. The increase in other operation expenses reflects $4.5 million associated with the work force reduction program. The Company also recognized higher employee benefit costs under new accounting rules adopted in 1993. See Note 2 to the financial statements for additional information on these new rules.
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, and the total average cost of energy supply (including purchased power) were as follows:
=============================================================== 1994 1993 1992 ----------------------- Total energy supply (millions of kilowatt-hours) 3,768 3,863 3,764 Sources of energy supply (percent) Coal 18 21 12 Oil 1 2 1 Gas 1 3 2 Purchased Power 80 74 85 Average cost of fuel per net kilowatt-hour generated (cents) Coal 2.19 2.02 2.28 Oil 3.89 4.11 2.40 Gas 5.19 4.87 4.28 Total average cost of energy supply 2.02 2.12 1.78
===============================================================
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in long-lived utility plant. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and preferred stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1994 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 growth in energy sales 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 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. 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 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 to sell electricity to other utilities. This may enhance the incentives for IPPs to build cogeneration plants for the Company's large industrial and commercial customers. 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 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.
Demand-side options -- programs that enable customers to lower or alter their peak energy requirements -- have been initiated by the Company and are a significant part of integrated resource planning. Customers can receive cash incentives for participating in these programs in addition to reducing 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. The ability to defer major construction projects in conjunction with regulatory precertification approval processes for both new plant additions and purchase power contracts should minimize the possibility of not being able to fully recover additional costs.
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. 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 reduce 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). In May 1992, the Company requested, and subsequently received, approval by the GPSC to reduce annual base revenues by $2.8 million, effective June 1992. The reduction included a base rate reduction of approximately $2.5 million spread among all classes of retail customers. An additional $0.3 million reduction resulted from the implementation of an experimental, time-of-use rate for certain commercial customers. As part of this rate settlement, it was informally agreed that the Company's earned rate of return on common equity should be 12.95 percent.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1994 was the addition of $30 million to utility plant. The majority of funds needed for gross property additions since 1992 have been provided from operating activities,
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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, 1994, the Company's capital structure consisted of 45.8 percent common equity, 9.9 percent preferred stock and 44.3 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 45 percent, preferred stock at 10 percent and debt at 45 percent.
Maturities and retirements of long-term debt were $5 million in 1994, $4 million in 1993 and $53 million in 1992.
The composite interest rates and dividend rates for the years 1992 through 1994 as of year-end were as follows:
=================================================================== 1994 1993 1992 ----------------------------- Composite interest rates on long-term debt 8.0% 8.0% 8.5% Composite preferred stock dividend rate 6.6% 6.6% 9.5% ===================================================================
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 $87 million ($34 million in 1995, $27 million in 1996, and $26 million in 1997). Actual construction costs may vary from this estimate because of such factors as 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 will be fully recovered.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.9 million will be needed by the end of 1997 for present sinking fund requirements and a capital lease buyout.
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 new law --may have a significant impact on the Company and other subsidiaries of the Southern electric system. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants will be required in two phases. Phase I compliance began in 1995, and affects eight generating plants -- some 10,000 megawatts of capacity or 35 percent of total capacity -- in the Southern electric system. 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 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 expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, and this would require some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1994 Annual Report
construction expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment has been installed on all fossil-fired units. Construction expenditures for Phase I compliance are estimated to total approximately $300 million through 1995 for The Southern Company, of which the Company's portion is approximately $2 million.
For Phase II sulfur dioxide compliance, The Southern Company could use emission allowances banked during Phase I and 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. Therefore, during the period 1996 through 2000, current compliance strategy could require total estimated construction expenditures of approximately $150 million. No construction expenditures are expected to be required of the Company to comply with Phase II requirements. 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 2 percent in annual revenue requirements from customers could be necessary to fully recover the Company's costs of compliance for both Phase I and II 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 by November 1995. 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.
A significant portion of costs related to the acid rain provision of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered.
The EPA continues to evaluate the need for a new short-term ambient air quality standard for sulfur dioxide. Preliminary results from an EPA study on the impact of a new standard indicate that a number of plants could be required to install sulfur dioxide controls. These controls would be in addition to the controls already required to meet the acid rain provision of the Clean Air Act. The EPA issued proposed rules in November 1994 and is required to take final action on this issue in 1996. The impact of any new standard will depend on the level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality standards for particulate matter, nitrogen oxides, 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 1995, 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 1994 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 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 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 new 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, 1994, the Company had $1.6 million of cash and $18 million of unused credit arrangements with banks to meet its short-term cash needs. The Company had $2.5 million of short-term bank borrowings at December 31, 1994. In December 1994, the Company renegotiated a two-year revolving credit arrangement with three of its existing banks for a total credit line of $20 million. The primary purpose of this additional credit is to provide interim funding for the Company's construction program.
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 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 levels, any foreseeable security sales. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.
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STATEMENTS OF INCOME For the Years Ended December 31, 1994, 1993, and 1992 Savannah Electric and Power Company 1994 Annual Report
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994, 1993, and 1992 Savannah Electric and Power Company 1994 Annual Report
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BALANCE SHEETS At December 31, 1994 and 1993 Savannah Electric and Power Company 1994 Annual Report
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BALANCE SHEETS At December 31, 1994 and 1993 Savannah Electric and Power Company 1994 Annual Report
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STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1994, 1993, and 1992 Savannah Electric and Power Company 1994 Annual Report
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NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 1994 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), and The Southern Development and Investment Group (SDIG). 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, beginning in mid-1995, will provide digital wireless communications services -- over the 800-megahertz frequency band -- to The Southern Company's subsidiaries and also will market these services to the public within the Southeast. Southern Electric designs, builds, owns, and operates power production 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. SDIG 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.
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 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:
=============================================================== 1994 1993 -------------------- (in thousands) Deferred income taxes $23,521 $24,890 Premium on reacquired debt 3,295 3,792 Deferred income tax credits (25,487) (26,173) --------------------------------------------------------------- Total $ 1,329 $ 2,509 ===============================================================
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 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 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 1994, uncollectible accounts continued to average less than 1 percent of revenues.
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NOTES (continued) Savannah Electric and Power Company 1994 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 1994, 2.9 percent in 1993, and 3.2 percent in 1992. The decrease in rates following 1992 reflects the Company's implementation of new depreciation rates approved by the GPSC. These new rates provide for a timely recovery of the investments in the Company's depreciable properties.
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.
Income Taxes
The Company, which is included in the consolidated federal income tax return filed by The Southern Company, 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.
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. Statement No. 109 required, among other things, conversion to the liability method of accounting for accumulated deferred income taxes. See Note 7 for additional information about Statement No. 109.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rates used by the Company to calculate AFUDC were 8.04 percent in 1994, 8.77 percent in 1993, and 11.27 percent in 1992.
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 the estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Value of Financial Instruments, the Company's only financial instrument that the carrying amount did not approximate fair value at December 31 was as follows:
================================================================ Long-Term Debt ----------------------- Carrying Fair Year Amount Value ---- ----------------------- (in millions) 1994 $157 $153 1993 154 164 ================================================================
The fair value for long-term debt was based on either closing market prices or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
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NOTES (continued) Savannah Electric and Power Company 1994 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. A qualified trust for medical benefits is funded to the extent deductible under federal income tax regulations. Amounts funded are primarily invested in debt and equity securities.
Effective January 1, 1993, the Company adopted FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. Statement No. 106 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.
Prior to 1993, consistent with regulatory treatment, the Company recognized costs on a cash basis as payments were made. The total cost of such benefits recognized by the Company in 1992 was $375 thousand.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension and postretirement medical and life 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 ------------------- 1994 1993 ------------------- (in thousands) Actuarial present value of benefit obligation: Vested benefits $35,227 $35,818 Non-vested benefits 2,069 1,992 ------------------------------------------------------------------ Accumulated benefit obligation 37,296 37,810 Additional amounts related to projected salary increases 7,393 5,974 ------------------------------------------------------------------ Projected benefit obligation 44,689 43,784 Less: Fair value of plan assets 27,165 26,446 Unrecognized net loss 10,950 9,449 Unrecognized prior service cost 1,510 1,685 Unrecognized net transition obligation 621 710 Adjustment required to recognize additional minimum liability 5,688 5,871 ------------------------------------------------------------------ Accrued pension cost recognized in the Balance Sheets $10,131 $11,365
===================================================================
The weighted average rates assumed in the actuarial calculations for the pension plan were:
================================================================== 1994 1993 1992 ------------------------------ Discount 8.00% 7.50% 8.00% Annual salary increase 5.25 4.75 5.00 Long-term return on plan assets 9.00 9.25 9.25
===================================================================
In accordance with Statement No. 87, an additional liability related to under-funded accumulated benefit obligations was reflected at December 31, 1994 and December 31, 1993. Corresponding net-of-tax balances of $0.5 million and $2.1 million were recognized as separate components of Common Stock Equity in the 1994 and 1993 Statements of Capitalization.
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NOTES (continued) Savannah Electric and Power Company 1994 Annual Report
================================================================
Postretirement Medical --------------------- 1994 1993 --------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $ 8,480 $ 8,632 Employees eligible to retire 825 898 Other employees 6,840 6,489 ----------------------------------------------------------------- Accumulated benefit obligation 16,145 16,019 Less: Fair value of plan assets 393 - Unrecognized net loss 3,106 4,124 Unrecognized transition obligation 9,817 10,362 ----------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 2,829 $ 1,533 =================================================================
Postretirement Life ---------------------- 1994 1993 ---------------------- (in thousands) Actuarial present value of benefit obligation: Retirees and dependents $2,514 $2,536 Employees eligible to retire 59 - Other employees 1,645 1,577 ------------------------------------------------------------------- Accumulated benefit obligation 4,218 4,113 Less: Fair value of plan assets - - Unrecognized net loss 91 262 Unrecognized transition obligation 3,204 3,382 ------------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ 923 $ 469 ===================================================================
The weighted average rates assumed in the actuarial calculations for the postretirement medical and life plans were:
======================================================= 1994 1993 ------------------ Discount 8.00% 7.50% Annual salary increase 5.50 5.00 Long-term return on plan assets 8.50 8.50
=======================================================
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 10.5 percent for 1994, decreasing gradually to 6.0 percent through the year 2000 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate of 1 percent would increase the accumulated medical benefit obligation at December 31, 1994, by $2.3 million and the aggregate of the service and interest cost components of the net retiree medical cost by $0.3 million.
Components of the plans' net costs are shown below:
=================================================================== Pension --------------------------- 1994 1993 1992 --------------------------- (in thousands) Benefits earned during the year $ 1,192 $1,188 $1,053 Interest cost on projected benefit obligation 3,279 2,741 2,429 Actual (return) loss on plan assets 27 (2,199) (1,266) Net amortization and deferral (1,474) 716 (227) ------------------------------------------------------------------- Net pension cost $ 3,024 $2,446 $1,989 ===================================================================
Of the above net pension amounts, $2.6 million in 1994, $2.0 million in 1993 and $1.7 million in 1992 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
================================================================ Postretirement Medical ------------------ 1994 1993 ------------------ (in thousands) Benefits earned during the year $ 528 346 Interest cost on accumulated benefit obligation 1,185 855 Amortization of transition obligation 545 545 Actual (return) loss on plan assets 6 - Net amortization and deferral 111 - ---------------------------------------------------------------- Net postretirement cost $2,375 $1,746 ================================================================
==================================================================
Postretirement Life ---------------------- 1994 1993 ---------------------- (in thousands) Benefits earned during the year $104 $ 97 Interest cost on accumulated benefit obligation 307 279 Amortization of transition obligation 178 178 ------------------------------------------------------------------ Net postretirement cost $589 $554 ==================================================================
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NOTES (continued) Savannah Electric and Power Company 1994 Annual Report
Of the above net postretirement medical and life insurance costs, $2.4 million in 1994 and $1.8 million in 1993 were charged to 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 1994, 1993 and 1992 were $377 thousand, $980 thousand and $316 thousand, respectively. The 1993 benefit costs reflect a one-time expense related to employees who were part of the work force reduction program.
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
In May 1992, the Company filed for, and subsequently received, GPSC approval to implement new base rates designed to decrease base operating revenues by $2.8 million annually. The reduction included a base rate reduction of approximately $2.5 million spread among all classes of customers, effective June 1992. An additional $0.3 million reduction resulted from the implementation of an experimental, time-of-use rate for certain commercial customers in August 1992.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently estimated to total $34 million in 1995, $27 million in 1996 and $26 million in 1997. The estimates include AFUDC of $0.7 million in 1995 and 1996, and $0.6 million in 1997. 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. In addition, 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
General
To the extent possible, the Company's construction program is expected to be financed from internal sources and from the issuance of additional long-term debt and preferred stock and capital contributions from The Southern Company. Should the Company be unable to obtain funds from these sources, the Company would have to use short-term indebtedness or other alternative, and possibly costlier, means of financing.
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. See Management's Discussion and Analysis for information regarding the Company's earnings coverage requirements.
Bank Credit Arrangements
At the beginning of 1995, unused credit arrangements with five banks totaled $18 million and expire at various times during 1995 and 1996.
The Company's revolving credit arrangements of $20 million, of which $11.5 million remained unused as of December 31, 1994, expire in December 1996. 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
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NOTES (continued) Savannah Electric and Power Company 1994 Annual Report
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.
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $1.5 million for 1994, 1993, and 1992. At December 31, 1994, estimated future minimum lease payments for non-cancelable operating leases were as follows:
======================================================== Amounts --------- (in millions) 1995 $1.1 1996 0.9 1997 0.7 1998 0.5
========================================================
6. LONG-TERM POWER SALES AGREEMENTS
The operating subsidiaries of The Southern Company, including the 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 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) 1994 $3 $445 $448 1993 2 976 978 1992 3 534 537
=================================================================
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, 1994, the tax-related regulatory assets and liabilities were $24 million and $25 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:
=============================================================== 1994 1993 1992 ---------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $11,736 $11,663 $ 6,630 Deferred - current year 2,106 1,906 7,407 - reversal of prior years (755) (1,383) (2,347) --------------------------------------------------------------- 13,087 12,186 11,690 --------------------------------------------------------------- State -- Currently payable 2,064 2,049 1,231 Deferred - current year 188 119 1,079 - reversal of prior years 86 (35) (192) --------------------------------------------------------------- 2,338 2,133 2,118 --------------------------------------------------------------- Total 15,425 14,319 13,808 Less income taxes charged (credited) to other income (864) (1,117) (758) --------------------------------------------------------------- Federal and state income taxes charged to operations $16,289 $15,436 $14,566 ===============================================================
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NOTES (continued) Savannah Electric and Power Company 1994 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
================================================================ 1994 1993 ----------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $57,830 $53,585 Property basis differences 12,956 13,871 Other 2,449 3,922 ---------------------------------------------------------------- Total 73,235 71,378 --------------------------------------------------------------- Deferred tax assets: Pension and other benefits 4,816 4,237 Other 3,959 4,616 ---------------------------------------------------------------- Total 8,775 8,853 ---------------------------------------------------------------- Net deferred tax liabilities 64,460 62,525 Portions included in current assets, net 6,326 4,422 ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $70,786 $66,947 ================================================================
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 1994, 1993, and 1992. At December 31, 1994, 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:
=============================================================== 1994 1993 1992 ----------------------------- Statutory federal tax rate 35% 35% 34% State income tax, net of federal income tax benefit 4 4 4 Other - (1) - --------------------------------------------------------------- Total effective tax rate 39% 38% 38% ===============================================================
The Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax agreement, each company's current and deferred tax expense is computed on a stand-alone basis, and consolidated tax savings are allocated to each company based on its 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.
In December 1993, the Company redeemed all 800,000 shares outstanding of its 9.5% Series Preferred Stock at the prescribed redemption price of $26.57 plus accrued dividends. 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 April 1994, the Company retired the remaining outstanding principal amount of $3.7 million of its 4 5/8 percent series First Mortgage Bonds due April 1994.
The sinking fund requirements of first mortgage bonds were satisfied by certification of property additions in 1993 and by cash redemption in 1994. See Note 10 "Long-Term Debt Due Within One Year" for details.
Details of pollution control obligations and other long-term debt at December 31 are as follows:
================================================================= 1994 1993 ------------------ (in thousands) Collateralized obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds -- Variable rate (5.65% at 1/1/95) due 2016 $ 4,085 $ 4,085 6 3/4% due 2022 13,870 13,870 ----------------------------------------------------------------- Total pollution control obligations $17,955 $17,955 ----------------------------------------------------------------- Capital lease obligations -- Combustion turbine equipment $ 980 $ 1,403 Transportation fleet 508 908 Notes Payable: 6.04% due 1995 3,500 - 6.035% due 1995 5,000 - ----------------------------------------------------------------- Total other long-term debt $ 9,988 $ 2,311 =================================================================
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NOTES (continued) Savannah Electric and Power Company 1994 Annual Report
Sinking fund requirements and/or maturities through 1999 applicable to long-term debt are as follows: $2.6 million in 1995; $0.2 million in 1996; $0.1 million in 1997; and no requirement is needed in 1998 and 1999.
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 leases combustion turbine generating equipment under a non-cancelable lease expiring in December 1995, with renewal options extending until 2010. The Company also 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 improvement fund/sinking fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
================================================================= 1994 1993 -------------------- (in thousands) Bond sinking fund requirements $1,350 $1,350 Less: Portion to be satisfied by certifying property additions - 1,350 ----------------------------------------------------------------- Cash sinking fund requirements 1,350 - Other long-term debt maturities 1,229 4,499 ----------------------------------------------------------------- Total $2,579 $4,499 =================================================================
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 1 2/3 times the requirements.
11. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Charter and Indentures contain certain limitations on the payment of cash dividends on preferred and common stocks. At December 31, 1994, approximately $57 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Mortgage Indenture.
12. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1994 and 1993 are as follows (in thousands):
================================================================== Net Income After Operating Operating Dividends on Quarter Ended Revenue Income Preferred Stock ------------------------------------------------------------------ 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
March 1993 $42,873 $ 6,123 $ 3,019 June 1993 52,875 9,301 6,211 September 1993 74,420 13,326 10,214 December 1993 48,274 5,484 2,015
==================================================================
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
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SELECTED FINANCIAL AND OPERATING DATA Savannah Electric and Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA Savannah Electric and Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA Savannah Electric and Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA Savannah Electric and Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Savannah Electric and Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Savannah Electric and Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Savannah Electric and Power Company 1994 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Savannah Electric and Power Company 1994 Annual Report
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STATEMENTS OF INCOME Savannah Electric and Power Company
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STATEMENTS OF INCOME Savannah Electric and Power Company
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STATEMENTS OF INCOME Savannah Electric and Power Company
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STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
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STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
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STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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BALANCE SHEETS Savannah Electric and Power Company
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SAVANNAH ELECTRIC AND POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1994
First Mortgage Bonds
Amount Interest Amount Series Issued Rate Outstanding Maturity ------------------------------------------------------------- (Thousands) (Thousands) 1993 $ 20,000 6-3/8% $ 20,000 7/1/03 1989 30,000 9-1/4% 28,950 10/1/19 1991 30,000 9-3/8% 29,700 7/1/21 1992 30,000 8.30% 30,000 7/1/22 1993 25,000 7.40% 25,000 7/1/23 -------- -------- $135,000 $133,650 ======== ========
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
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SAVANNAH ELECTRIC AND POWER COMPANY
SECURITIES RETIRED DURING 1994
First Mortgage Bonds
Principal Interest Series Amount Rate --------------------------------------------------------------------- (Thousands) 1964 $3,715 4-5/8% 1989 1,050 9-1/4% 1991 300 9-3/8% ------ $5,065 ======
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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 1995 annual meeting of stockholders.
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
ALABAMA
(a)(1) Identification of directors of ALABAMA.
Elmer B. Harris (1) President and Chief Executive Officer of ALABAMA Age 55 Served as Director since 3-1-89
Bill M. Guthrie Executive Vice President of ALABAMA Age 61 Served as Director since 12-16-88
Whit Armstrong (2) Age 47 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 70 Served as Director since 2-26-93
A. W. Dahlberg (2) Age 54 Served as Director since 4-22-94
Peter V. Gregerson, Sr. (2) Age 66 Served as Director since 10-22-93
Crawford T. Johnson, III (2) Age 70 Served as Director since 4-18-69
Carl E. Jones, Jr. (2) Age 54 Served as Director since 4-22-88
Wallace D. Malone, Jr. (2) Age 58 Served as Director since 6-22-90
William V. Muse (2) Age 55 Served as Director since 2-26-93
John T. Porter (2) Age 63 Served as Director since 10-22-93
Gerald H. Powell (2) Age 68 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 57 Served as Director since 4-22-88
William J. Rushton, III (2) Age 65 Served as Director since 9-18-70
James H. Sanford (2) Age 50 Served as Director since 8-1-83
John C. Webb, IV (2) Age 52 Served as Director since 4-22-77
John W. Woods (2) Age 63 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 22, 1994) for one year until the next annual meeting or until a successor is elected and qualified.
III-1
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.
(b)(1) Identification of executive officers of ALABAMA.
Elmer B. Harris (1) President, Chief Executive Officer and Director Age 55 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 51 Served as Executive Officer since 12-3-91
Charles D. McCrary Executive Vice President Age 43 Served as Executive Officer since 1-1-91
T. Harold Jones Senior Vice President Age 64 Served as Executive Officer since 12-1-91
(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 22, 1994) 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.
(c)(1) Identification of certain significant employees. None.
(d)(1) Family relationships. None.
(e)(1) Business experience.
Elmer B. Harris - Elected in 1989; Chief Executive Officer. He previously served as Senior Executive Vice President of GEORGIA from 1986 to 1989. Director of SOUTHERN and AmSouth Bancorporation.
Bill M. Guthrie - Elected in 1988; also served since 1991 as Chief Production Officer of SOUTHERN system and Executive Vice President and Chief Production Officer of SCS; 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, Trust Company Bank, Trust Company of Georgia, Protective Life Corporation and Equifax, Inc.
Peter V. Gregerson, Sr. - Chairman Emeritus of Gregerson's Foods, Inc. (retail groceries), Gadsden, Alabama. Director of AmSouth Bank of Gadsden, Alabama.
III-2
Crawford T. Johnson, III - Chairman of Coca-Cola Bottling Company United, Inc., Birmingham, Alabama. Director of Protective Life Corporation, AmSouth Bancorporation and Russell Corporation.
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.
William V. Muse - President and Chief Executive Officer of Auburn University. He previously served as President of the University of Akron from 1984 to 1992.
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 and AmSouth Bancorporation.
James H. Sanford - President, 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 - Chairman and Chief Executive Officer, AmSouth Bancorporation (multi-bank holding company), Birmingham, Alabama. 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.
T. Harold Jones - Elected in 1991; responsible primarily for providing the overall management of the Fossil Generation, Hydro Generation, Power Generation Services and Fuels Departments. He previously served as Vice President - Fossil Generation from 1986 to 1991.
(f)(1) Involvement in certain legal proceedings. None.
III-3
GEORGIA
(a)(2) Identification of directors of GEORGIA.
H. Allen Franklin President and Chief Executive Officer. Age 50 Served as Director since 1-1-94.
Warren Y. Jobe Executive Vice President, Treasurer and Chief Financial Officer. Age 54 Served as Director since 8-1-82
Bennett A. Brown (1) Age 65 Served as Director since 5-15-80
A. W. Dahlberg (1) Age 54 Served as Director since 6-1-88
William A. Fickling, Jr. (1) Age 62 Served as Director since 4-18-73
L. G. Hardman III (1) Age 55 Served as Director since 6-25-79
James R. Lientz, Jr. (1) Age 51 Served as Director since 7-1-93
William A. Parker, Jr. (1) Age 67 Served as Director since 5-19-65
G. Joseph Prendergast (1) Age 49 Served as Director since 1-20-93
Herman J. Russell (1) Age 64 Served as Director since 5-18-88
Gloria M. Shatto (1) Age 63 Served as Director since 2-20-80
William Jerry Vereen (1) Age 54 Served as Director since 5-18-88
Carl Ware (1) (2) Age 51 Served as Director since 2-15-95
Thomas R. Williams (1) Age 66 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 18, 1994) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Ware whose election was effective on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he/she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of GEORGIA acting solely in their capacities as such.
(b)(2) Identification of executive officers of GEORGIA.
H. Allen Franklin President, Chief Executive Officer and Director Age 50 Served as Executive Officer since 1-1-94
Warren Y. Jobe Executive Vice President, Treasurer, Chief Financial Officer and Director Age 54 Served as Executive Officer since 5-19-82
Dwight H. Evans Executive Vice President - External Affairs Age 46 Served as Executive Officer since 4-19-89
III-4
W. G. Hairston, III Executive Vice President - Nuclear Age 50 Served as Executive Officer since 6-1-93
Gene R. Hodges Executive Vice President - Customer Operations Age 56 Served as Executive Officer since 11-19-86
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 54 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
Gale E. Klappa Senior Vice President - Marketing Age 44 Served as Executive Officer since 2-19-92
Fred D. Williams Senior Vice President - Bulk Power Markets Age 50 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 18, 1994) for one year until the next annual meeting or until his successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of GEORGIA acting solely in their capacities as such.
(c)(2) Identification of certain significant employees. None.
(d)(2) Family relationships. None.
(e)(2) Business experience.
H. Allen Franklin - President and Chief Executive Officer since January 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 from serving 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, Trust Company Bank, Trust Company of Georgia, Protective Life Corporation and Equifax, Inc.
William A. Fickling, Jr. - Co-Chairman of the Board and Chief Executive Officer of Beech Street Corporation (provider of managed care services).
L. G. Hardman III - Chairman of the Board of 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.
III-5
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 April 1994. 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.
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.
Dwight H. Evans - Executive Vice President - External Affairs since 1989.
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.
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 June 1994. Senior Vice President - Administrative Services from 1992 to 1994 and Vice President - Northern Region from 1990 to 1992.
Gale E. Klappa - Senior Vice President - Marketing since 1992. Vice President - Public Relations of SCS from 1981 to 1992.
Fred D. Williams - Senior Vice President - Bulk Markets since 1992. Vice President - Bulk Power Markets from 1984 to 1992.
(f)(2) Involvement in certain legal proceedings. None.
III-6
GULF
(a)(3) Identification of directors of GULF.
Travis J. Bowden President and Chief Executive Officer Age 56 Served as Director since 2-1-94
Reed Bell, Sr., M.D. (1) Age 68 Served as Director since 1-17-86
Paul J. DeNicola (1) Age 46 Served as Director since 4-19-91
Fred C. Donovan (1) Age 54 Served as Director since 1-18-91
W. D. Hull, Jr. (1) Age 62 Served as Director since 10-14-83
C. W. Ruckel (1) Age 67 Served as Director since 4-20-62
J. K. Tannehill (1) Age 61 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 28, 1994) 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.
(b)(3) Identification of executive officers of GULF.
Travis J. Bowden President, Chief Executive Officer and Director Age 56 Served as Executive Officer since 2-1-94
F. M. Fisher, Jr. Vice President - Employee and External Relations Age 46 Served as Executive Officer since 5-19-89
John E. Hodges, Jr. Vice President - Customer Operations Age 51 Served as Executive Officer since 5-19-89
G. Edison Holland, Jr. (1) Vice President - Power Generation/ Transmission and Corporate Counsel Age 42 Served as Executive Officer since 4-25-92
Earl B. Parsons, Jr. (2) Vice President - Power Generation and Transmission Age 56 Served as Executive Officer since 4-14-78
A. E. Scarbrough Vice President - Finance Age 58 Served as Executive Officer since 9-21-77
(1) Effective March 13, 1995.
(2) Resigned effective March 11, 1995, to assume the position of Senior Vice President - Fossil and Hydro Generation at ALABAMA.
Each of the above is currently an executive officer of GULF, serving a term running from the last annual meeting of the directors (July 22, 1994) for one year until the next annual meeting or until his successor is elected and qualified.
III-7
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.
(c)(3) Identification of certain significant employees. None.
(d)(3) Family relationships. None.
(e)(3) 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 effective January 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 Sun 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 1987 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 Tannehill 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 Federal Savings 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.
Earl B. Parsons, Jr. - Elected Vice President - Power Generation and Transmission in 1989; responsible for generation and transmission of electrical energy.
A. E. Scarbrough - Elected Vice President - Finance in 1980; responsible for all accounting and financial services of GULF.
(f)(3) Involvement in certain legal proceedings. None.
III-8
MISSISSIPPI
(a)(4) Identification of directors of MISSISSIPPI.
David M. Ratcliffe President and Chief Executive Officer Age 46 Served as Director since 4-24-91
Paul J. DeNicola (1) Age 46 Served as Director since 5-1-89
Edwin E. Downer (1) Age 63 Served as Director since 4-24-84
Robert S. Gaddis (1) Age 63 Served as Director since 1-21-86
Walter H. Hurt, III (1) Age 59 Served as Director since 4-6-82
Aubrey K. Lucas (1) Age 60 Served as Director since 4-24-84
Gerald J. St. Pe (1) Age 55 Served as Director since 1-21-86
Dr. Philip J. Terrell (1) Age 41 Served as Director since 2-22-95
N. Eugene Warr (1) Age 59 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 5, 1994) for one year until the next annual meeting or until a successor is elected and qualified, except for Dr. Terrell 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.
(b)(4) Identification of executive officers of MISSISSIPPI.
David M. Ratcliffe (1) President, Chief Executive Officer and Director Age 46 Served as Executive Officer since 4-24-91
H. E. Blakeslee Vice President - Customer Services and Marketing Age 54 Served as Executive Officer since 1-25-84
F. D. Kuester Vice President - Power Generation and Delivery Age 44 Served as Executive Officer since 3-1-94
Don E. Mason Vice President - External Affairs and Corporate Services Age 53 Served as Executive Officer since 7-27-83
Michael W. Southern Vice President, Secretary, Treasurer and Chief Financial Officer Age 42 Served as Executive Officer since 1-1-95
(1) Elected Senior Vice President of SOUTHERN in March 1995, however, Mr. Ratcliffe will maintain his present position until his successor is elected.
Each of the above is currently an executive officer of MISSISSIPPI, serving a term running from the last annual meeting of the directors (April 27, 1994) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Southern 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 MISSISSIPPI acting solely in their capacities as such.
III-9
(c)(4) Identification of certain significant employees. None.
(d)(4) Family relationships. None.
(e)(4) Business experience.
David M. Ratcliffe - President and Chief Executive Officer since 1991. He previously served as Executive Vice President of SCS from 1989 to 1991 and Vice President of SCS from 1985 to 1989.
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 since 1990. President and Chief Executive Officer, Unifirst Bank for Savings, F.A., Midland Division, Meridian, Mississippi from 1985 to 1990.
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.
Gerald J. St. Pe - President of Ingalls Shipbuilding and Senior Vice President of Litton Industries, Inc. since 1985. Director of Merchants and Marine Bank, Pascagoula, Mississippi.
Dr. 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). Vice chairman of the Board of SouthTrust Bank of Mississippi, formerly The Jefferson Bank, Biloxi, Mississippi.
H. E. Blakeslee - Elected Vice President in 1984. Primarily responsible for rate design, economic analysis and revenue forecasting, economic development, marketing and district operations.
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 the external affairs functions, including governmental and regulatory affairs, corporate communications, security, materials 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, information resources and risk management. 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.
(f)(4) Involvement in certain legal proceedings. None.
III-10
SAVANNAH
(a)(5) Identification of directors of SAVANNAH.
Arthur M. Gignilliat, Jr. President and Chief Executive Officer Age 62 Served as Director since 9-1-82
Helen Quattlebaum Artley (1) Age 67 Served as Director since 5-17-77
Paul J. DeNicola (1) Age 46 Served as Director since 3-14-91
Brian R. Foster (1) Age 45 Served as Director since 5-16-89
Walter D. Gnann (1) Age 59 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 49 Served as Director since 5-17-83
James M. Piette (1) Age 70 Served as Director since 6-12-73
Arnold M. Tenenbaum (1) Age 58 Served as Director since 5-17-77
Frederick F. Williams, Jr. (1) Age 67 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 17, 1994) 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.
(b)(5) Identification of executive officers of SAVANNAH.
Arthur M. Gignilliat, Jr. President, Chief Executive Officer and Director Age 62 Served as Executive Officer since 2-15-72
W. Miles Greer Vice President - Marketing and Customer Services Age 51 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 43 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 (May 17, 1994) 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.
(c)(5) Identification of certain significant employees. None.
(d)(5) Family relationships. None.
(e)(5) Business experience.
Arthur M. Gignilliat, Jr. - Elected President and Chief Executive Officer in 1984. Director of Savannah Foods and Industries, Inc.
III-11
Helen Quattlebaum Artley - Homemaker and Civic Worker.
Paul J. DeNicola - President and Chief Executive Officer of SCS effective January 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 Builders of Savannah.
James M. Piette - Retired Vice Chairman, Board of Directors, Union Camp Corporation.
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.
(f)(5) Involvement in certain legal proceedings. None.
GEORGIA's Mr. Thomas R. Williams failed to file on a timely basis a single report disclosing one transaction on Forms 4 and 5 as required by Section 16 of the Securities Exchange Act of 1934. Mr. William G. Hairston, III also failed to file on a timely basis a Form 3 as required by Section 16 of the Securities Act of 1934.
III-12
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
(a) 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 1994 for each of the operating affiliates (ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH).
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III-15
III-16
III-17
III-18
STOCK OPTION GRANTS IN 1994
(b) Stock Option Grants. The following table sets forth all stock option grants to the named executive officers of each operating subsidiary during the year ending December 31, 1994.
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DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
(e)(1) 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 1994 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, 1994, the applicable compensation levels and years of accredited service are presented in the following tables:
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SAVANNAH has in effect a qualified, trusteed, noncontributory, defined benefit pension plan which provides pension benefits to employees upon retirement at the normal retirement age after designated periods of accredited service and at a specified compensation level. The plan provides pension benefits under a formula which includes each participant's years of service with the Southern system and average annual earnings of the highest three of the final ten 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 1994 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 ten years credited to both Mr. Bowden and Mr. Holland pursuant to individual supplemental pension agreements.
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As of December 31, 1994, the applicable compensation levels and years of accredited service are presented in the following table:-
(e)(2) 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 ten 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.
------------------------------- 1 The plan benefits are subject to the maximum benefit limitations set forth in Section 415 of the Internal Revenue Code.
III-27
(f) Compensation of Directors. -------------------------
(1) Standard Arrangements. The following table presents compensation paid to the directors, during 1994 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 ranges from 75 to 100 percent of the annual retainer fee in effect on the date of retirement, based upon length of service. Payments continue for the greater of the lifetime of the participant or 10 years.
(2) Other Arrangements. No director received other compensation for services as a director during the year ending December 31, 1994 in addition to or in lieu of that specified by the standard arrangements specified above.
(g) Employment Contracts and Termination of Employment and Change in Control Arrangements.
None.
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(h) Report on Repricing of Options. ------------------------------
None.
(i) 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, is Chairman and Chief Executive Officer of AmSouth Bancorporation.
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ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) 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.
(b) 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, 1994. 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, 1994.
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III-31
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III-33
III-34
III-35
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ALABAMA
(a) Transactions with management and others.
During 1994, ALABAMA, in the ordinary course of business, paid premiums amounting to approximately $584,358 for various types of insurance policies purchased from Protective Life Insurance Company, a subsidiary of Protective Life Corporation, a company in which Mr. William J. Rushton, III, a director of ALABAMA, owns an interest and of which he served as Chairman.
ALABAMA believes that these transactions have been on terms representing competitive market prices that are no less favorable than those available from others.
(b) Certain business relationships. None.
(c) Indebtedness of management. None.
(d) Transactions with promoters. None.
GEORGIA
(a) Transactions with management and others.
Mr. G. Joseph Prendergast is Chairman of Wachovia Bank of Georgia, N.A., and Mr. James R. Lientz, Jr. is President of NationsBank of Georgia. During 1994, 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 1994, GEORGIA leased a building from Riverside Manufacturing Co. for approximately $73,000. Mr. William J. Vereen is Chief Executive Officer, President, Treasurer and Director of Riverside Manufacturing Co.
(b) Certain business relationships. None.
(c) Indebtedness of management. None.
(d) Transactions with promoters. None.
GULF
(a) Transactions with management and others.
The firm of Beggs & Lane, P.A. serves as local counsel for GULF and received from GULF approximately $1,095,340 for services rendered. Mr. G. Edison Holland, Jr. is a partner in the firm and also serves as Vice President and Corporate Counsel of GULF.
(b) Certain business relationships. None.
(c) Indebtedness of management. None.
(d) Transactions with promoters. None.
MISSISSIPPI
(a) Transactions with management and others.
During 1994, MISSISSIPPI was indebted in a maximum amount of $9 million to Hancock Bank, of which Mr. Leo W. Seal, Jr. serves as Chairman of the Board and Chief Executive Officer. Mr. Seal retired from MISSISSIPPI's board of directors effective September 6, 1994.
(b) Certain business relationships. None.
(c) Indebtedness of management. None.
(d) Transactions with promoters. None.
III-36
SAVANNAH
(a) Transactions with management and others.
Mr. Tenenbaum is a Director of First Union National Bank of Georgia, and Mr. Foster is President of NationsBank of Georgia, N.A., in Savannah. During 1994, these banks furnished a number of regular banking services in the ordinary course of business to SAVANNAH. SAVANNAH intends to maintain normal banking relations with all of the aforesaid banks in the future.
(b) Certain business relationships. None.
(c) Indebtedness of management. None.
(d) 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 1994 only the following registrant filed a Current Report on Form 8-K:
ALABAMA filed a Form 8-K dated November 30, 1994 to facilitate a security sale.
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 23, 1995
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 and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: W. P. Copenhaver Elmer B. Harris. A. D. Correll Earl D. McLean, Jr. Paul J. DeNicola William A. Parker, Jr. Jack Edwards William J. Rushton, III H. Allen Franklin Gloria M. Shatto Bruce S. Gordon Herbert Stockham L. G. Hardman III
By: /s/ Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
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 23, 1995
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 (Principal Financial Officer)
David L. Whitson Vice President and Comptroller (Principal Accounting Officer)
Directors: Whit Armstrong Wallace D. Malone, Jr. Philip E. Austin William V. Muse 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 Crawford T. Johnson, III John Cox Webb, IV Carl E. Jones, Jr. John W. Woods
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
IV-2
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 23, 1995
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)
C. B. Harreld Vice President and Comptroller (Principal Accounting Officer)
Directors: Bennett A. Brown Herman J. Russell A. W. Dahlberg William Jerry Vereen L. G. Hardman III Carl Ware James R. Lientz, Jr. Thomas R. Williams G. Joseph Prendergast
By: /s/Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
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 23, 1995
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 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 23, 1995
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: David M. Ratcliffe, President and Chief Executive Officer
By: /s/ Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
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.
David M. Ratcliffe 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 Gerald J. St. Pe' Robert S. Gaddis N. Eugene Warr Walter H. Hurt, III
By: /s/ Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
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 23, 1995
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 James M. Piette Brian R. Foster Arnold M. Tenenbaum Walter D. Gnann Frederick F. Williams, Jr.
By: /s/ Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
IV-4
Exhibit 21. Subsidiaries of the Registrants.
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 15, 1995 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, 33-23153, 33-51433, 33-54415, and 33-57951.
/s/ ARTHUR ANDERSEN LLP Atlanta, Georgia March 23, 1995
IV-6
Exhibit 23(b)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 15, 1995 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 No. 33-49653.
/s/ ARTHUR ANDERSEN LLP Birmingham, Alabama March 23, 1995
IV-7
Exhibit 23(c)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 15, 1995 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 No. 33-49661.
/s/ ARTHUR ANDERSEN LLP Atlanta, Georgia March 23, 1995
IV-8
Exhibit 23(d)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 15, 1995 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 23, 1995
IV-9
Exhibit 23(e)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 15, 1995 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 23, 1995
IV-10
Exhibit 23(f)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 15, 1995 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 Nos. 33-45757 and 33-52509.
/s/ ARTHUR ANDERSEN LLP Atlanta, Georgia March 23, 1995
IV-11
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 15, 1995. Our report on the consolidated financial statements includes an explanatory paragraph which states that an uncertainty exists with respect to the actions of the regulators regarding recoverability of the investment in the Rocky Mountain pumped storage hydroelectric project, as discussed in Note 4 to The Southern Company's consolidated financial statements. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed under Item 14(a)(2) herein as it relates to The Southern Company and its subsidiaries (pages S-2 through S-4) are the responsibility of The Southern Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state 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 15, 1995
IV-12
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 15, 1995. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed under Item 14(a)(2) herein as it relates to Alabama Power Company (pages S-5 through S-7) are the responsibility of Alabama Power Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state 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 15, 1995
IV-13
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 15, 1995. Our report on the financial statements includes an explanatory paragraph which states that an uncertainty exists with respect to the actions of the regulators regarding the recoverability of Georgia Power Company's investment in the Rocky Mountain pumped storage hydroelectric project, as discussed in Note 4 to Georgia Power Company's financial statements. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed under Item 14(a)(2) herein as it relates to Georgia Power Company (pages S-8 through S-10) are the responsibility of Georgia Power Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state 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 15, 1995
IV-14
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 15, 1995. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed under Item 14(a)(2) herein as it relates to Gulf Power Company (pages S-11 through S-13) are the responsibility of Gulf Power Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state 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 15, 1995
IV-15
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 15, 1995. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed under Item 14(a)(2) herein as it relates to Mississippi Power Company (pages S-14 through S-16) are the responsibility of Mississippi Power Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state 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 15, 1995
IV-16
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 15, 1995. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed under Item 14(a)(2) herein as it relates to Savannah Electric and Power Company (pages S-17 through S-19) are the responsibility of Savannah Electric and Power Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state 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 15, 1995
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
S-1
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1994 (Stated in Thousands of Dollars)
S-2
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1993 (Stated in Thousands of Dollars)
S-3
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1992 (Stated in Thousands of Dollars)
S-4
ALABAMA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1994 (Stated in Thousands of Dollars)
S-5
ALABAMA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1993 (Stated in Thousands of Dollars)
S-6
ALABAMA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1992 (Stated in Thousands of Dollars)
S-7
GEORGIA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1994 (Stated in Thousands of Dollars)
S-8
GEORGIA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1993 (Stated in Thousands of Dollars)
S-9
GEORGIA POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1992 (Stated in Thousands of Dollars)
S-10
GULF POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1994 (Stated in Thousands of Dollars)
S-11
GULF POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1993 (Stated in Thousands of Dollars)
S-12
GULF POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1992 (Stated in Thousands of Dollars)
S-13
MISSISSIPPI POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1994 (Stated in Thousands of Dollars)
S-14
MISSISSIPPI POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1993 (Stated in Thousands of Dollars)
S-15
MISSISSIPPI POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1992 (Stated in Thousands of Dollars)
S-16
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1994 (Stated in Thousands of Dollars)
S-17
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1993 (Stated in Thousands of Dollars)
S-18
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1992 (Stated in Thousands of Dollars)
S-19
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.
(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).)
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(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.)
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(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 December 1, 1994. (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 and in Certificate of Notification, File No. 70- 8443, as Exhibit E.)
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* (c) 2 - Supplemental Indenture dated as of June 1, 1994, between GEORGIA and Chemical Bank, as Trustee.
* (c) 3 - Supplemental Indenture dated as of September 1, 1994, between GEORGIA and Chemical Bank, as Trustee.
(c) 4 - Indenture dated as of December 1, 1994, between GEORGIA and Trust Company Bank, as Trustee. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit E.)
(c) 5 - First Supplemental Indenture dated as of December 15, 1994, between GEORGIA and Trust Company Bank, as Trustee. (Designated in Certificate of Notification, File No. 70- 8461, as Exhibit 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 September 1, 1994. (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 and in Certificate of Notification, File No. 70-8229, as Exhibits E and F.)
MISSISSIPPI
(e) - Indenture dated as of September 1, 1941, between MISSISSIPPI and Bankers Trust Company, as Successor Trustee, and indentures supplemental thereto through March 1, 1994. (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 and in Form 8- K dated March 8, 1994, File No. 0-6849, as Exhibit 4.)
E-4
SAVANNAH
(f) - Indenture dated as of March 1, 1945, between SAVANNAH and NationsBank of Georgia, National Association, as Trustee, and indentures supplemental thereto through July 1, 1993. (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) and in Form 8-K dated July 22, 1993, 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 - 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) 6 - Agreement dated as of January 27, 1959 and Amendment No. 1 dated as of October 27, 1982, among SEGCO, ALABAMA and GEORGIA. (Designated in Registration No. 2-59634 as Exhibit 5(c) and in GEORGIA's Form 10-K for the year ended December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2).)
E-5
(a) 7 - 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) 8 - 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) 9 - 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) 10 - 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) 11 - 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) 12 - 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) 13 - 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) 14 - 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) 15 - 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) 16 - 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) 17 - 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).)
E-6
(a) 18 - 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) 19 - 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) 20 - 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) 21 - 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) 22 - 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) 23 - 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) 24 - 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) 25 - 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) 26 - 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.)
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(a) 27 - 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) 28 - 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) 29 - 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) 30 - 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. (Designated in Form U-1, File No. 70-7843, as Exhibit B-1.)
(a) 31 - Plant Robert W. Scherer Unit No. Four Operating Agreement by and among GEORGIA, FP&L and JEA, dated as of December 31, 1990. (Designated in Form U-1, File No. 70-7843, as Exhibit B-2.)
(a) 32 - 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) 33 - 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) 34 - 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).)
E-8
(a) 35 - 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) 36 - 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) 37 - 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) 38 - 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) 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.)
E-9
(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.)
E-10
(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 - Service Contract dated as of December 12, 1994, between SCS and Mobile Energy Services Company, Inc.
(a) 59 - The Southern Company Outside Directors Stock Plan. (Designated in Registration No. 33-54415 as Exhibit 4(c).)
* (a) 60 - Amendment No. 1 dated as of June 15, 1994, to the Plant Robert W. Scherer Unit Number Four Amended and Restated Purchase and Ownership Participation Agreement.
* (a) 61 - Amendment No. 1 dated as of June 15, 1994, to the Plant Robert W. Scherer Unit Number Four Operating Agreement.
(a) 62 - 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) 63 - 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) 64 - 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) 65 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1994.
* (a) 66 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1994.
E-11
(a) 67 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1989. (Designated in Registration No. 33-23152 as Exhibit 4(c).)
(a) 68 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1989. (Designated in Form U-1, File No. 70-7654, as Exhibit B-1 and in Form U-1, File No. 70-8435, as Exhibit B-4(b).)
* (a) 69 - Pension Plan For Employees of ALABAMA, Amended and Restated effective as of January 1, 1989.
* (a) 70 - Pension Plan For Employees of GEORGIA, Amended and Restated effective as of January 1, 1989.
* (a) 71 - Pension Plan For Employees of SCS, Amended and Restated effective as of January 1, 1989.
* (a) 72 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993.
* (a) 73 - Supplemental Benefit Plan for ALABAMA.
* (a) 74 - Supplemental Benefit Plan for GEORGIA.
* (a) 75 - Supplemental Benefit Plan for SCS and SEI.
* (a) 76 - The Deferred Compensation Plan for the Directors of The Southern Company.
* (a) 77 - The Southern Company Outside Directors Pension Plan.
* (a) 78 - The Deferred Compensation 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)5 herein.
(b) 3 - Agreement dated as of January 27, 1959 and Amendment No. 1 dated as of October 27, 1982, among SEGCO, ALABAMA and GEORGIA. See Exhibit 10(a)6 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)32 herein.
E-12
(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)33 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)34 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)35 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)36 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)37 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.
E-13
(b) 17 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit 10(a)53 herein.
* (b) 18 - Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, to Agreement dated January 27, 1959, among SEGCO, ALABAMA and GEORGIA.
(b) 19 - Operating Agreement for the Joseph M. Farley Nuclear Plant between ALABAMA and Southern Nuclear dated as of December 23, 1991. See Exhibit 10(a)62 herein.
* (b) 20 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1994. See Exhibit 10(a)65 herein.
* (b) 21 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1994. See Exhibit 10(a)66 herein.
(b) 22 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)67 herein.
(b) 23 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)68 herein.
* (b) 24 - Pension Plan For Employees of ALABAMA, Amended and Restated effective as of January 1, 1989. See Exhibit 10(a)69 herein.
* (b) 25 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)72 herein.
* (b) 26 - Supplemental Benefit Plan for ALABAMA. See Exhibit 10(a)73 herein.
* (b) 27 - The Deferred Compensation Plan for the Southern Electric System. See Exhibit 10(a)78 herein.
* (b) 28 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)77 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)5 herein.
E-14
(c) 3 - Agreement dated as of January 27, 1959 and Amendment No. 1 dated as of October 27, 1982, among SEGCO, ALABAMA and GEORGIA. See Exhibit 10(a)6 herein.
(c) 4 - Joint Committee Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)7 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)8 herein.
(c) 6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between GEORGIA and OPC. See Exhibit 10(a)9 herein.
(c) 7 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between GEORGIA and OPC. See Exhibit 10(a)10 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)11 herein.
(c) 9 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between GEORGIA and OPC. See Exhibit 10(a)12 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)13 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)14 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)15 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)16 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)17 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)18 herein.
E-15
(c) 16 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)19 herein.
(c) 17 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and Dalton. See Exhibit 10(a)20 herein.
(c) 18 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)21 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)22 herein.
(c) 20 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)23 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)24 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)25 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)26 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)27 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)28 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)29 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. See Exhibit 10(a)30 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. See Exhibit 10(a)31 herein.
E-16
(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)32 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)33 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)34 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)35 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)36 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)37 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.
E-17
(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.)
E-18
* (c) 54 - Amendment No. 1 dated as of June 15, 1994, to the Plant Robert W. Scherer Unit Number Four Amended and Restated Purchase and Ownership Participation Agreement. See Exhibit 10(a)60 herein.
* (c) 55 - Amendment No. 1 dated as of June 15, 1994, to the Plant Robert W. Scherer Unit Number Four Operating Agreement. See Exhibit 10(a)61 herein.
* (c) 56 - Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, to Agreement dated as of January 27, 1959, among SEGCO, ALABAMA and GEORGIA. See Exhibit 10(b)18 herein.
(c) 57 - Nuclear Services Agreement between Southern Nuclear and GEORGIA dated as of October 31, 1991. See Exhibit 10(a)63 herein.
(c) 58 - Nuclear Managing Board Agreement among GEORGIA, OPC, MEAG and Dalton dated as of November 12, 1990. See Exhibit 10(a)64 herein.
* (c) 59 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1994. See Exhibit 10(a)65 herein.
* (c) 60 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1994. See Exhibit 10(a)66 herein.
(c) 61 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)67 herein.
(c) 62 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)68 herein.
* (c) 63 - Pension Plan For Employees of GEORGIA, Amended and Restated effective as of January 1, 1989. See Exhibit 10(a)70 herein.
* (c) 64 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)72 herein.
* (c) 65 - Supplemental Benefit Plan for GEORGIA. See Exhibit 10(a)74 herein.
* (c) 66 - The Deferred Compensation Plan for the Southern Electric System. See Exhibit 10(a)78 herein.
* (c) 67 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)77 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.
E-19
(d) 2 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 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)28 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)29 herein.
(d) 5 - 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)32 herein.
(d) 6 - 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)33 herein.
(d) 7 - Unit Power Sales Agreement dated July 19, 1988, between FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)34 herein.
(d) 8 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(d) 9 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(d) 10 - 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) 11 - Unit Power Sales Agreement dated December 8, 1990, between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(d) 12 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(d) 13 - 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-20
* (d) 14 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1994. See Exhibit 10(a)65 herein.
* (d) 15 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1994. See Exhibit 10(a)66 herein.
(d) 16 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)67 herein.
(d) 17 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)68 herein.
* (d) 18 - Pension Plan For Employees of GULF, Amended and Restated effective as of January 1, 1989.
* (d) 19 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)72 herein.
* (d) 20 - Supplemental Benefit Plan for GULF.
* (d) 21 - The Deferred Compensation Plan for the Southern Electric System. See Exhibit 10(a)78 herein.
* (d) 22 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)77 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)5 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)32 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)33 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)34 herein.
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(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)35 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)36 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)37 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, 1994. See Exhibit 10(a)65 herein.
* (e) 15 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1994. See Exhibit 10(a)66 herein.
(e) 16 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)67 herein.
(e) 17 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)68 herein.
* (e) 18 - Pension Plan For Employees of MISSISSIPPI, Amended and Restated effective as of January 1, 1989.
* (e) 19 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)72 herein.
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* (e) 20 - Supplemental Benefit Plan for MISSISSIPPI.
* (e) 21 - The Deferred Compensation Plan for the Southern Electric System. See Exhibit 10(a)78 herein.
* (e) 22 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)77 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)5 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)34 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)35 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)36 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)37 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.
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* (f) 11 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1994. See Exhibit 10(a)65 herein.
* (f) 12 - The Southern Company Executive Productivity Improvement Plan, effective January 1, 1994. See Exhibit 10(a)66 herein.
(f) 13 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)67 herein.
(f) 14 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1989. See Exhibit 10(a)68 herein.
* (f) 15 - Employees' Retirement Plan of SAVANNAH, Amended and Restated effective January 1, 1989.
* (f) 16 - Supplemental Executive Retirement Plan of SAVANNAH.
* (f) 17 - Deferred Compensation Plan for Key Employees of SAVANNAH.
* (f) 18 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1993. See Exhibit 10(a)72 herein.
* (f) 19 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)77 herein.
* (f) 20 - Deferred Compensation Plan for Directors of SAVANNAH.
(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.
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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.
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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 15, 1995, File No. 1-3526, as Exhibit 27.)
ALABAMA
(b) - Financial Data Schedule. (Designated in Form 8-K dated February 15, 1995, File No. 1-3164, as Exhibit 27.)
GEORGIA
(c) - Financial Data Schedule. (Designated in Form 8-K dated February 15, 1995, File No. 1-6468, as Exhibit 27.)
GULF
(d) - Financial Data Schedule. (Designated in Form 8-K dated February 15, 1995, File No. 0-2429, as Exhibit 27.)
MISSISSIPPI
(e) - Financial Data Schedule. (Designated in Form 8-K dated February 15, 1995, File No. 0-6849, as Exhibit 27.)
SAVANNAH
(f) - Financial Data Schedule. (Designated in Form 8-K dated February 15, 1995, File No. 1-5072, as Exhibit 27.)