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 Georgia; its charter was granted by the Secretary of State on August 5, 1921.
SOUTHERN also owns all the outstanding common stock of SEI, Southern Nuclear, SCS (the system service company), 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. Southern Nuclear provides services to the Southern electric system's nuclear plants.
SEGCO owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000 volt transmission lines extending from Plant Gaston to the Georgia state line at which point connection is made with the GEORGIA transmission line system.
THE SOUTHERN SYSTEM
The transmission facilities of each of the operating affiliates and SEGCO are connected to the respective company's own generating plants and other sources of power and are interconnected with the transmission facilities of the other operating affiliates and SEGCO by means of heavy-duty high voltage lines. (In the case of GEORGIA's integrated transmission system, see Item 1 - BUSINESS - "Territory Served" herein.)
Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. 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
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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 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 and statistical, finance and treasury, taxes, insurance and pensions, corporate, rates, budgeting, public relations, employee relations, systems and procedures and other services with respect to business and operations. SOUTHERN also has a contract with SCS for certain of these specialized services.
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 of generation facilities in the international market. SEI currently operates two domestic independent power production projects totaling 225 megawatts and is one-third owner of one of these (which produces 180 megawatts). It has a contract to sell electric energy to Virginia Electric and Power Company from a facility SEI is developing (through subsidiaries) in King George, Virginia. Upon completion, currently planned for 1996, SEI will operate the 220 megawatt coal-fired plant and own 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 December 1993, SOUTHERN completed the purchase of a 35% interest in Edelnor for the purchase price of $73 million. Edelnor is a utility located in Northern Chile that owns and operates a transmission grid and a 96 megawatt generating facility and is building an additional 150 megawatt facility.
SEI has continued to render consulting services and market SOUTHERN system expertise in the United States and throughout the world. It contracts with other public utilities, commercial concerns and government agencies for the rendition of services and the licensing of intellectual property. In addition, SEI engages in energy management-related services and activities.
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, because of the absence of any assured return or rate of return, they also involve a higher
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degree of risk. SOUTHERN expects to make substantial investments over the period 1994-1996 in these and other new businesses.
CERTAIN FACTORS AFFECTING THE INDUSTRY
The electric utility industry is expected to become increasingly competitive in the future as a result of the enactment of the Energy Act (see each registrant's "Management's Discussion and Analysis - Future Earnings Potential" in Item 7 herein), deregulation, competing technologies and other factors. In recent years the electric utility industry in general has experienced problems in a number of areas including the uncertain cost of capital needed for construction programs, difficulty in obtaining sufficient return on invested capital and in securing adequate rate increases when required, high costs and other issues associated with compliance with environmental and nuclear regulations, changes in regulatory climate, prudence audits and the effects of inflation and other factors on the costs of operations and construction expenditures. The SOUTHERN system has been experiencing certain of these problems in varying degrees and management is unable to predict the future effect of these or other factors upon its operations and financial condition.
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 1994 through 1996 by the operating affiliates, SEGCO, SCS and Southern Nuclear are estimated as follows: (in millions)
*Does not add due to changes made in subsidiaries' construction budget subsequent to approval of SOUTHERN system construction budget.
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 for the period 1994 through 1996 do not include amounts which may be spent by 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.)
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Estimated construction costs in 1994 are expected to be apportioned approximately as follows: (in millions)
*SCS and Southern Nuclear plan capital additions to general plant in 1994 of $26 million and $1 million, respectively, while SEGCO plans capital additions of $14 million to generating facilities. Does not add due to changes made in subsidiaries' construction budget subsequent to approval of SOUTHERN system construction budget.
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; cost of capital and SEI securing a contract(s) to buy or build additional generating facilities.
The operating affiliates do not have any baseload generating plants under construction and current energy demand forecasts do not require any additional baseload generating facilities before 2011. However, within the service area, the construction of combustion turbine peaking units with an aggregate capacity of approximately 1,700 megawatts is planned to be completed by 1996. In addition, significant construction of transmission and distribution facilities and upgrading of generating plants will be continuing.
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, 1993, 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.
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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 33.1% for Unit 4 of total plant capacity. See Item 2 - PROPERTIES - "Proposed Sales 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.
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 OPC, MEAG and Dalton and excludes demand associated with power purchased from 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. The reserve margin for the Southern electric system at that time was 13.2%. For information on the other registrants' 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 -
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"Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and GEORGIA's financial statements in Item 8 herein.)
OTHER ELECTRIC GENERATION FACILITIES
Through special purpose subsidiaries, SOUTHERN owns a 50% interest in Freeport, a 35% interest in Edelnor, a 55.3% interest Alicura and a 33.3% interest in a co-generation facility in Hawaii. 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, 1993, was as follows:
* Represents a concession contract that provides SEI with the rights to use the generation.
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JOINTLY-OWNED FACILITIES
ALABAMA has sold an undivided interest in two units of Plant Miller to AEC. GEORGIA has sold undivided interests in certain generating plants and other related facilities to OPC, MEAG, Dalton, FP&L and JEA. The percentages of ownership resulting from these sales 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, as described below) as agent for the joint owners. See "Proposed Sales 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 1994 for Unit 1 and 1996 for Unit 2 and, with regard to a portion of a 5% 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 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. GEORGIA has held preliminary discussions regarding the potential disposition of its remaining interest in the project.
PROPOSED SALES OF PROPERTY
In 1991 and 1993, GEORGIA completed the first two in a series of four separate transactions to sell Unit 4 of Plant Scherer to FP&L and JEA for a total price of approximately $806 million, including any gains on these transactions. FP&L would eventually own approximately 76.4% of this unit, with JEA owning the remainder. The capacity from this unit was previously dedicated to off-system sales contracts with Gulf States that were suspended in 1988. GEORGIA will continue to operate the unit.
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The 1991 and 1993 sales and the remaining transactions are scheduled as follows:
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, 1989, to December 31, 1993, the operating affiliates, SEGCO, and other (i.e. SCS, Southern Nuclear and, beginning in 1993, various of the special purpose subsidiaries) gross property additions and retirements were as follows:
(1) Includes approximately $62 million attributable to property sold to AEC in 1992. (2) Includes approximately $480 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 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
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SOUTHERN board of directors' refusal of an earlier demand by the plaintiffs was wrongful. The plaintiffs appealed the dismissal to the U.S. Court of Appeals for the Eleventh Circuit.
(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) OHIO RIVER COMPANY, ET AL.VS. GULF, ET AL. (U.S. District Court for Southern District of Ohio, Western Division)
In 1993, a complaint against GULF and SCS was filed in federal district court in Ohio by two companies with which GULF had contracted for the transportation by barge for certain GULF coal supplies. The complaint alleges breach of the contract by GULF and seeks damages estimated by the plaintiffs to be in excess of $85 million.
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 GULF'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 and SEI 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)
EDWARD L. ADDISON Chairman and CEO Age 63 Elected in 1983; responsible primarily for the formation of overall corporate policy. He was elected Chairman of SOUTHERN effective January 1994.
A. W. DAHLBERG President and Director Age 53 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.
PAUL J. DENICOLA Executive Vice President and Director Age 45 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 49 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 CEO of GEORGIA effective January 1994.
ELMER B. HARRIS Executive Vice President and Director Age 54 Elected in 1989; President and Chief Executive Officer of ALABAMA since 1989 and, beginning 1991, Executive Vice President of SOUTHERN. He previously served as Senior Executive Vice President of GEORGIA from 1986 to 1989.
W. L. WESTBROOK Financial Vice President Age 54 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 60 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 26, 1993) for one year until the next annual meeting or until his successor is elected and qualified.
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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:
There is no market for the other registrants' common stock, all of which is owned by SOUTHERN. On February 28, 1994, the closing price of SOUTHERN's common stock was $20-5/8.
(b) Number of SOUTHERN's common stockholders at December 31, 1993: 237,105
Each of the other registrants have one common stockholder, SOUTHERN.
(c) Common dividends are payable at the discretion of each registrant's board of directors. The common dividends paid by SOUTHERN and the operating affiliates to their stockholder(s) for the past two years were as follows: (in thousands)
In January 1994, SOUTHERN's board of directors authorized a two-for-one common stock split in the form of a stock distribution for each share held as of February 7, 1994. For all reported common stock data, the number of common shares outstanding and per share amounts for earnings, dividends, and market price have been adjusted to reflect the stock distribution.
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The dividend paid per share by SOUTHERN was 27.5c. for each quarter of 1992 and 28.5c. for each quarter of 1993. SOUTHERN's common dividend for the first quarter of 1994 was raised to 29.5c. per share.
The amount of common dividends 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, 1993, were as follows:
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-78 through II-91.
GEORGIA. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-123 through II-137.
GULF. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II- 166 through II-179.
MISSISSIPPI. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-207 through II-220.
SAVANNAH. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-245 through II-258.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
SOUTHERN. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-8 through II-15.
ALABAMA. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-53 through II-58.
GEORGIA. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-95 through II-101.
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-141 through II-147.
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-183 through II-189.
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-224 through II-230.
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ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 1993 FINANCIAL STATEMENTS
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ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT The Southern Company and Subsidiary Companies 1993 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 three directors who are not employees, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and 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 subsidiaries 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 regulatory proceedings are concluded. 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/ E. L. Addison /s/ W. L. Westbrook - ------------------------------------ ---------------------------- Edward L. Addison W. L. Westbrook Chairman and Chief Executive Officer Financial Vice President
II-6 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND TO THE STOCKHOLDERS OF THE SOUTHERN COMPANY:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company (a Delaware corporation) and its subsidiaries as of December 31, 1993 and 1992, 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, 1993. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-16 through II-37) referred to above present fairly, in all material respects, the financial position of The Southern Company and its subsidiaries as of December 31, 1993 and 1992, 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 regulatory proceedings are concluded. 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 & Co.
Atlanta, Georgia February 16, 1994
II-7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The Southern Company and Subsidiary Companies 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS AND DIVIDENDS
The Southern Company's 1993 financial performance exceeded the strong results recorded for 1992, and set several new records. The company's financial strength continued to gain momentum for the third consecutive year. In January 1994, The Southern Company board of directors increased the quarterly dividend rate by 3.5 percent, and approved a two-for-one common stock split in the form of a stock distribution. 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. For 1993, The Southern Company's net income of $1.0 billion established a new record high and the company's common stock reached an all-time high closing price during the year of 23 3/8 -- surpassing the record of 19 1/2 set in 1992. Also, return on average common equity reached the highest level since 1986.
Earnings reported for 1993 totaled $1,002 million or $1.57 per share, an increase of $49 million or 6 cents per share from the previous year. Both 1993 and 1992 earnings were affected by special non-operating or non-recurring items. After excluding these special items in both years, earnings from operations of the ongoing business of selling electricity were $1,016 million or $1.59 per share, an increase of $77 million or 10 cents per share compared with 1992. The special items that affected 1993 and 1992 earnings were as follows:
In 1993, several items -- both positive and negative -- had an impact on earnings, which resulted in a net reduction of $14 million. These items were: (1) The conclusion of a settlement agreement -- discussed later -- with Gulf States Utilities (Gulf States) increased earnings. (2) The second in a series of four separate transactions to sell Plant Scherer Unit 4 to two Florida utilities increased earnings. (3) Environmental clean-up costs incurred at sites located in Alabama and Georgia decreased earnings. (4) Costs associated with a transportation fleet reduction program decreased earnings. The improvements in 1993 earnings resulted primarily from increased retail energy sales and continued emphasis on effective cost controls.
The special items that increased 1992 earnings were primarily related to additional settlement provisions from Gulf States, and to gains on the sale of Gulf States common stock received in 1991.
Returns on average common equity were 13.43 percent in 1993, 13.42 percent in 1992, and 12.74 percent in 1991. Dividends paid on common stock during 1993 were $1.14 per share or 28 1/2 cents per quarter. During 1992 and 1991, dividends paid per share were $1.10 and $1.07, respectively. In January 1994, The Southern Company board of directors raised the quarterly dividend to 29 1/2 cents per share or an annual rate of $1.18 per share.
REVENUES
Operating revenues increased in 1993 and 1992 and decreased in 1991 as a result of the following factors:
II-8 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
Retail revenues of $7.3 billion in 1993 increased 7.4 percent from last year, compared with an increase of 1.6 percent in 1992. Under fuel cost recovery provisions, fuel revenues generally equal fuel expense -- including the fuel component of purchased energy -- and do not affect net income.
Sales for resale revenues within the service area were $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 for resale within the service area were $409 million in 1992, down 1.9 percent from the prior year. The decrease resulted from certain municipalities and cooperatives in the service area retaining more of their own generation at facilities jointly owned with Georgia Power.
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components were as follows:
Capacity revenues decreased in 1993 and 1992 because the amount of capacity under contract declined by some 500 megawatts and 300 megawatts, respectively. In 1994, the contracted capacity will decline another 400 megawatts.
Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour sales for 1993 and the percent change by year were as follows:
The rate of growth in 1993 retail energy sales was the highest since 1986. Residential energy sales registered the highest annual increase in two decades as a result of hotter-than-normal summer weather and the addition of 46,000 new customers. Commercial sales were also affected by the warm summer. Industrial energy sales in 1993 and 1992 showed moderate growth, reflecting a recovery in the business and economic conditions in The Southern Company's service area. Energy sales to retail customers are projected to grow at an average annual rate of 1.7 percent during the period 1994 through 2004.
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 have decreased for the third consecutive year primarily as a result of the scheduled decline in megawatts of capacity under contract. In addition, the decline in 1992 and 1991 sales was also influenced by fluctuations in prices for oil and natural gas, the primary fuel sources for utilities with which the company has long-term contracts. When oil and gas prices fall below a certain level, these customers can generate electricity to meet their requirements more economically. However, the fluctuation in these energy sales, excluding the impact of contractual declines, had minimal effect on earnings because The Southern Company is paid for dedicating specific amounts of its generating capacity to these utilities.
EXPENSES
Total operating expenses of $6.7 billion for 1993 were up 6.5 percent compared with the prior year. 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 resulting from additional utility plant being placed into service. The transportation fleet reduction program and environmental clean-up 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.
In 1992, total operating expenses of $6.3 billion were at the same level reported for 1991. The costs to produce and deliver electricity in 1992 declined by $165 million primarily as a result of less energy being sold and continued effective cost controls. However, expenses in 1991 were reduced by proceeds from a settlement
II-9 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
agreement with Gulf States that more than offset the decline in 1992 expenses when compared with 1991. Deferred expenses related to Plant Vogtle in 1992 increased by $47 million when compared with the prior year.
Fuel costs constitute the single largest expense for The Southern Company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
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 slightly higher average cost of fuel per net kilowatt-hour generated. Fuel and purchased power costs in 1992 decreased $137 million or 5.0 percent compared with 1991 primarily because 1.1 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.
Income taxes for 1993 increased $69 million compared with the prior year. The increase is attributable to a number of factors, including a 1 percent increase in the corporate federal income tax rate effective January 1993, the second sale of additional ownership interest in Plant Scherer Unit 4, and the increase in taxable income from operations. For 1992, income taxes rose $11 million or 1.7 percent above the amount reported for 1991.
For the fifth consecutive year, total gross interest charges and preferred stock dividends declined from amounts reported in the previous year. The declines are attributable to lower interest rates and significant refinancing activities during the past two years. In 1993, these costs were $831 million - -- down $21 million or 2.3 percent. These costs for 1992 decreased $71 million. As a result of favorable market conditions during 1993, some $3.0 billion of senior securities was issued for the primary purpose of retiring higher-cost debt and preferred stock.
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 regulatory matters.
Georgia Power has completed two of four separate transactions to sell Unit 4 of Plant Scherer to two Florida utilities. The remaining transactions are scheduled to take place in 1994 and 1995. If the sales take place as planned, Georgia Power could realize an after-tax gain currently estimated to total approximately $20 million. See Note 7 to the financial statements for additional information.
In early 1994, Georgia Power and the system service company announced work force reduction programs that are estimated to reduce 1994 earnings by some $55 million. These actions will assist in efforts to control the growth in operating expenses.
II-10 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
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.
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) will have a profound 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 law also includes provisions to streamline the licensing process for new nuclear plants. The Southern Company is preparing to meet the challenge of this major change in the traditional business practices 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, and 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, pressure for legislation to allow retail wheeling will continue. If The Southern Company does not remain a low-cost producer and provide quality service, the company's retail energy sales growth, as well as new long-term contracts for energy sales outside the service area, could be limited, and this could significantly erode earnings.
An important part of the Energy Act was to amend the Public Utility Holding Company Act of 1935 (PUHCA) and allow holding companies to form exempt wholesale generators and foreign utility companies to sell power largely free of regulation under PUHCA. These new 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 1993, investments of some $315 million were made in entities that own and operate generating facilities in various international markets. In the near term, Southern Electric is expected to have minimal effect on earnings, but the possibility exists that it could be a prime contributor to future earnings growth.
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's 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. Expansion and increased utilization of these programs will be contingent upon sharing of cost savings between the customers and the utility. Besides promoting energy efficiency, another benefit of these programs could be the ability to defer the need to construct baseload generating facilities further into the future. The ability to defer major construction projects in conjunction with precertification approval processes of such projects by the respective state public service commissions in Alabama, Georgia, and Mississippi will diminish the possible exposure to prudency disallowances and the resulting impact on earnings. In addition, Georgia Power has conducted a competitive bidding process for additional peaking capacity needed in 1996 and 1997. To meet expected requirements for 1996, Georgia Power has filed a plan with the state public service commission for certification of a four-year purchase power contract and for an ownership interest in a combustion turbine peaking unit.
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 regulatory matters.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate schedules and power sales contracts that The Southern Company has with its sales for resale customers. The FERC currently is reviewing the rate of return on common equity included in some of 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 reduce earnings if such costs are not fully recovered. The Clean Air Act is discussed later under "Environmental Matters."
II-11 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112, Employers' Accounting for Postemployment Benefits, which must be effective by 1994. The new standard requires that all types of benefits provided to former or inactive employees and their families prior to retirement be accounted for on an accrual basis. These benefits include salary continuation, severance pay, supplemental unemployment benefits, disability-related benefits, job training, and health and life insurance coverage. In 1993, The Southern Company adopted Statement No. 112, with no material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which is effective in 1994. Statement No. 115 supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities. The Southern Company adopted the new rules January 1, 1994, with no material effect on the financial statements.
FINANCIAL CONDITION
OVERVIEW
The Southern Company's financial condition is now the strongest since the mid-1980s. Record levels of performance were set in 1993 related to earnings, market price of common stock, and energy sold to retail customers. In January 1994, The Southern Company board of directors increased the common stock dividend for the third consecutive year, and approved a two-for-one common stock split in the form of a stock distribution.
Another major change in The Southern Company's financial condition was gross property additions of $1.4 billion to utility plant. The majority of funds needed for gross property additions since 1990 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.
On January 1, 1993, The Southern Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes. See notes 2 and 9 to the financial statements, regarding the impact of these changes.
CAPITAL STRUCTURE
The company achieved a ratio of common equity to total capitalization -- including short-term debt -- of 43.5 percent in 1993, compared with 42.8 percent in 1992 and 41.5 percent in 1991. The company's goal is to maintain the common equity ratio generally within a range of 40 percent to 45 percent.
During 1993, the operating companies sold $2.2 billion of first mortgage bonds and, through public authorities, $385 million of pollution control revenue bonds, at a combined weighted interest rate of 6.5 percent. Preferred stock of $426 million was issued at a weighted dividend rate of 5.7 percent. The operating companies continued to reduce financing costs by retiring higher-cost bonds and preferred stock. Retirements, including maturities, of bonds totaled $2.5 billion during 1993, $2.8 billion during 1992, and $1.0 billion during 1991. Retirements of preferred stock totaled $516 million during 1993, $326 million during 1992, and $125 million during 1991. As a result, the composite interest rate on long-term debt decreased from 9.2 percent at December 31, 1990, to 7.6 percent at December 31, 1993. During this same period, the composite dividend rate on preferred stock declined from 8.5 percent to 6.4 percent.
In 1993, The Southern Company raised $205 million from the issuance of new common stock under the Dividend Reinvestment and Stock Purchase Plan (DRIP) and the Employee Savings Plan. At the close of 1993, the company's common stock had a market value of $22.00 per share, compared with a book value of $11.96 per share. The market-to-book value ratio was 184 percent at the end of 1993, compared with 168 percent at year-end 1992 and 156 percent at year-end 1991.
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The construction program of the operating companies is budgeted at $1.5 billion for 1994, $1.3 billion for 1995, and $1.5 billion for 1996. The total is $4.3 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.
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
II-12 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
service area, the construction of combustion turbine peaking units of approximately 1,700 megawatts of capacity is planned to be completed by 1996 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 $789 million will be required by the end of 1996 for present sinking fund requirements, redemptions announced, and maturities of long-term debt. Also, the operating subsidiaries plan to continue a program 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 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 must be implemented 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.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate 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 allocating 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 market for emission allowances is developing slower than expected. However, The Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, and this has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment would be installed on all fossil-fired units. Under this Phase I compliance approach, additional construction expenditures are estimated to total approximately $275 million through 1995.
Phase II compliance costs are expected to be higher because requirements are stricter and all fossil-fired generating plants are affected. For 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 construction expenditures ranging from approximately $450 million to $800 million. However, the full impact of Phase II compliance cannot now be determined with certainty, pending the 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 3 percent in revenue requirements from customers could be necessary to fully recover the cost of compliance for both Phase I and Phase 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.
There can be no assurance that all Clean Air Act costs will be recovered.
Metropolitan Atlanta is classified as a non-attainment area with regard to the ozone ambient air quality standards. Title I of the Clean Air Act requires the state of Georgia to conduct specific studies and establish new control rules by November 1994 -- 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
II-13 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
requirements, on some Georgia Power plants. Final attainment rules, based on modeling studies, could require installation of additional controls for nitrogen oxide emissions as early as 1997. Compliance with any new rules could result in significant additional costs. The 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 study will serve as the basis for 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 is expected to take some action on this issue in 1994. 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 1994 or 1995, the EPA is expected to issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
The Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the 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.
Several major pieces of environmental legislation are in the process of being reauthorized or amended by Congress. These include: the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; and the Resource Conservation and Recovery 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 for lawsuits alleging damages caused by electromagnetic fields exists.
SOURCES OF CAPITAL
In early 1994, The Southern Company sold -- through a public offering -- common stock with proceeds totaling $120 million. The company may require additional equity capital during the remainder of 1994. The amount and timing of additional equity capital to be raised in 1994 -- 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 1994 for the DRIP and the employee 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. However, the type and timing of any financings -- if needed -- will depend on market conditions and regulatory approval.
II-14 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
Completing the sale of Unit 4 of Plant Scherer will provide some $260 million of cash during the years 1994 and 1995.
As required by the Nuclear Regulatory Commission, Alabama Power and Georgia Power established external sinking funds for nuclear decommissioning costs. For 1994 through 2000, the combined amount to be funded for both Alabama Power and Georgia Power totals $36 million annually. The cumulative effect of funding over this 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."
To meet short-term cash needs and contingencies, the system companies had approximately $178 million of cash and cash equivalents and $1.1 billion of unused credit arrangements with banks at the beginning of 1994.
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. The coverage ratios were, at the end of the respective years, as follows:
*Savannah Electric's requirement is 2.50.
II-15 CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1993, 1992, and 1991 The Southern Company and Subsidiary Companies 1993 Annual Report
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993, 1992, and 1991
The accompanying notes are an integral part of these statements.
II-16 CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993, 1992, and 1991 The Southern Company and Subsidiary Companies 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-17 CONSOLIDATED STATEMENTS OF BALANCE SHEETS At December 31, 1993, and 1992 The Southern Company and Subsidiary Companies 1993 Annual Report
The accompanying notes are an integral part of these balance sheets.
II-18 CONSOLIDATED BALANCE SHEETS (continued) At December 31, 1993 and 1992 The Southern Company and Subsidiary Companies 1993 Annual Report
The accompanying notes are an integral part of these balance sheets.
II-19 CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 1993 and 1992 The Southern Company and Subsidiary Companies 1993 Annual Report
II-20 CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 1993 and 1992 The Southern Company and Subsidiary Companies 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-21 NOTES TO FINANCIAL STATEMENTS The Southern Company and Subsidiary Companies 1993 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 Electric International (Southern Electric), Southern Nuclear Operating Company (Southern Nuclear), and various other subsidiaries related to foreign utility operations and domestic non-utility operations. At this time, the operations of the other subsidiaries are not material. 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 to the subsidiary companies. 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.
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, 1993, include $2.6 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.
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.
Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $137 million in 1993, $132 million in 1992, and $162 million in 1991. 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. Georgia Power -- based on its ownership interests -- and Alabama Power currently estimate their liability under this law to be approximately $39 million and $46 million, respectively. These obligations are recorded in the Consolidated Balance Sheets.
DEPRECIATION AND NUCLEAR DECOMMISSIONING
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3 percent in 1993, 1992, and 1991. 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.
II-22 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
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. Reasonable assurance may be in the form of an external sinking fund, a surety method, or prepayment. Alabama Power and Georgia Power have established external sinking funds to comply with the NRC's regulations. Prior to the enactment of these regulations, Alabama Power and Georgia Power had reserved nuclear decommissioning costs. 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.
The estimated cost of decommissioning and the amounts being recovered through rates at December 31, 1993, for Alabama Power's Plant Farley and Georgia Power's plants Hatch and Vogtle -- based on its ownership interests -- were as follows:
The amounts in the internal reserve are being transferred into the external trust fund over a set period of time as approved by the respective state public service commissions.
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 regulatory requirements, changes in technology, and changes in costs of labor, materials, and equipment.
PLANT VOGTLE PHASE-IN PLANS
In 1987 and 1989, the Georgia Public Service Commission (GPSC) ordered that the allowed costs of Plant Vogtle, a two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased into rates under plans that meet the requirements of Financial Accounting Standards Board (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. Units 1 and 2 began commercial operation in May 1987 and May 1989, respectively. The accounting orders were for the periods from the date of each unit's commercial operation until October 1987 and 1989, respectively. 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:
The unrecovered balance above includes approximately $160 million related to the adoption in 1993 of FASB Statement No. 109, Accounting for Income Taxes. See Note 9 for information about Statement No. 109.
II-23
NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
Each GPSC order calls 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. These deferred returns are included in the above amounts, except for the equity component in the case of the Unit 2 accounting order.
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.
In years prior to 1993, income taxes were accounted for and reported under Accounting Principles Board Opinion No. 11. 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.
AFUDC AND DEFERRED RETURN
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 companies to calculate AFUDC during the years 1991 through 1993 ranged from a before-income-tax rate of 4.9 percent to 11.4 percent. Deferred income taxes related to capitalized debt cost were $5 million, $4 million, and $7 million in 1993, 1992, and 1991, respectively. After Plant Vogtle units 1 and 2 began commercial operation in 1987 and 1989, respectively, Georgia Power imputed a deferred return similar to AFUDC on its investment in the units under the short-term cost deferrals and phase-in plans, as discussed earlier. AFUDC and the deferred return, net of income tax, as a percent of consolidated net income were 1.7 percent in 1993, 1.8 percent in 1992, and 6.0 percent in 1991. The deferred return was discontinued in October 1991 after the allowed investment in Plant Vogtle was fully reflected in rates.
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, all financial instruments of The Southern Company -- for which the carrying amount does not approximate fair value -- are shown in the table below at December 31:
The fair values of nuclear decommissioning trusts and investment securities were based on listed closing market prices. The fair values for long-term debt and preferred
II-24 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
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. In 1992, Georgia Power converted to the inventory method of accounting for certain emergency spare parts. This conversion resulted in a regulatory liability that will be amortized as a credit to income over approximately four years. This conversion will not have a material effect on net income.
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 asset representing the future recoverability of this cost. The amount was $73 million and $70 million at December 31, 1993 and 1992, respectively. In 1994, an estimated 71 percent of the 1993 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 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.
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. A qualified trust for medical benefits has been established for funding amounts to the extent deductible under federal income tax regulations. Amounts funded are primarily invested in debt and equity securities. Accrued costs of life insurance benefits, other than current cash payments for retirees, currently are not being funded.
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 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. As a result of regulatory treatment allowed by the operating companies' respective public service commissions, the adoption of Statement No. 106 did not have a material impact on consolidated net income.
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 these 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 and 1991 were $42 million and $36 million, respectively.
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. Retiree medical and life insurance information is shown only for 1993 because Statement
II-25 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
No. 106 was adopted as of January 1, 1993, on a prospective basis. The funded status of the plans at December 31 was as follows:
The weighted average rates assumed in the above actuarial calculations were:
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 11.3 percent for 1993, 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 by 1 percent would increase the accumulated medical benefit obligation at December 31, 1993, by $129 million and the aggregate of the service and interest cost components of the net retiree medical cost by $14 million.
Components of the plans' net cost are shown below:
Of the above net pension amounts, pension income of $9 million in 1993 and pension expense of $2 million in 1992 and $11 million in 1991 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Of the above net postretirement medical and life insurance costs recorded in 1993, $64 million was charged to operating expenses, $21 million was deferred, and the remainder was charged to construction and other accounts.
II-26 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
WORK FORCE REDUCTION PROGRAMS
The system companies have incurred additional costs for work force reduction programs. The costs related to these programs were $35 million, $37 million, and $72 million for the years 1993, 1992, and 1991, 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 $19 million at December 31, 1993.
3. LITIGATION AND REGULATORY MATTERS
RETAIL RATEPAYERS' SUIT CONCLUDED
In March 1993, several retail ratepayers of Georgia Power filed a civil complaint in the Superior Court of Fulton County, Georgia, against Georgia Power, The Southern Company, the system service company, and Arthur Andersen & Co. The complaint alleged that Georgia Power obtained excessive rate increases by improper accounting for spare parts and sought actual damages estimated by the plaintiffs to be in excess of $60 million -- plus treble and punitive damages -- for alleged violations of the Georgia Racketeer Influenced and Corrupt Organizations Act and other state statutes, statutory and common law fraud, and negligence. These state law allegations were substantially the same as those included in a 1989 suit brought in federal district court in Georgia. That suit and similar ones filed in Alabama, Florida, and Mississippi federal courts were subsequently dismissed.
The defendants' motions to dismiss the current complaint were granted by the Superior Court of Fulton County, Georgia, in July 1993. In January 1994, the plaintiffs' appeal of the dismissal to the Supreme Court of Georgia was rejected, and this matter is concluded.
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. The plaintiffs have appealed the dismissal to the U.S. Court of Appeals for the 11th Circuit.
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 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.
GULF POWER COAL BARGE TRANSPORTATION SUIT
In 1993, a complaint against Gulf Power and the system service company was filed in federal district court in Ohio by two companies with which Gulf Power had contracted for the transportation by barge for certain Gulf Power coal supplies. The complaint alleges breach of the contract by Gulf Power and seeks damages estimated by the plaintiffs to be in excess of $85 million.
II-27 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
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 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.
The APSC issued an order in December 1991 that reduced a scheduled 2.03 percent annual increase in rates to 1.03 percent, effective January 1992. The 1 percent reduction will remain in effect through 1994. The rate reduction was designed to refund to retail ratepayers a portion of the benefits from a settled contract dispute with Gulf States Utilities Company (Gulf States). The present value of this portion of the settlement -- amounting to some $60 million -- is being amortized to income to offset the rate reduction in accordance with the APSC's rate order. See Note 8 for additional information concerning the Gulf States settlement.
Also in the December 1991 rate order, the APSC reaffirmed its satisfaction with the ratemaking mechanism and stated that it did not foresee any further review or changes in the procedures until after 1994. The ratemaking procedures will remain in effect after 1994 unless the APSC votes to modify or discontinue them.
GEORGIA POWER'S DEMAND-SIDE CONSERVATION PROGRAMS
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that rate riders previously approved by the GPSC for recovery of Georgia Power's costs incurred in connection with demand-side conservation programs were unlawful. The judge held that the GPSC lacked statutory authority to approve such rate riders except through general rate case proceedings and that those procedures had not been followed. Georgia Power suspended collection of the demand-side conservation costs and appealed the court's decision to the Georgia Court of Appeals. In December 1993, the GPSC approved Georgia Power's request for an accounting order allowing Georgia Power to defer all current unrecovered and future costs related to these programs until the superior court's decision is reversed or until the next general rate case proceedings. An association of industrial customers has filed a petition for review of the accounting order in superior court. Georgia Power's costs related to these conservation programs through 1993 were $60 million, of which $15 million has been collected and the remainder deferred. The estimated costs, assuming no change in the programs certified by the GPSC, are $38 million in 1994 and $40 million in 1995.
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 1991 and the latest in 1994. In 1993, the Mississippi Public Service Commission (MPSC) ordered Mississippi Power to review and propose changes that would enhance the plan. Mississippi Power filed a revised plan, and the MPSC approved PEP-2 on January 4, 1994. Under PEP-2, Mississippi Power's rate of return will be measured on retail net investment rather than on common equity, as previously calculated. Also, the number of indicators used to evaluate Mississippi Power's performance was reduced to three 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 before a public hearing is required. PEP-2 will remain in effect until the MPSC modifies or terminates the plan.
II-28 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
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 occur as a result of this proceeding would be effective 60 days after a proper notice of the proceeding is published. A notice was published on May 10, 1991.
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.
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.
4. CONSTRUCTION PROGRAM
GENERAL
The operating companies are engaged in continuous construction programs, currently estimated to total some $1.5 billion in 1994, $1.3 billion in 1995, and $1.5 billion in 1996. These estimates include AFUDC of $34 million in 1994, $41 million in 1995, and $35 million in 1996. 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, 1993, 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 1,700 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.
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 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 cost and disposition of the project's capacity output. In the event Georgia Power cannot demonstrate to the GPSC the project's economic viability based on current ownership, construction schedule, and costs, then part or all of such costs may have to be written off. At December 31, 1993, Georgia Power's investment in the project amounted to approximately $197 million. 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 $199 million. The plant is currently scheduled to begin commercial operation in 1995. Georgia Power has held preliminary discussions with other parties regarding the potential disposition of its remaining interest in the project.
The ultimate outcome of this matter cannot now be determined.
5. FINANCING, INVESTMENT, AND COMMITMENTS
GENERAL
In early 1994, The Southern Company sold -- through a public offering -- 5.6 million shares of common stock with proceeds totaling $120 million. The company may require additional equity capital during the remainder of 1994. The amount and timing of additional equity capital to be raised in 1994 -- 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.
II-29 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
To the extent possible, the operating companies' construction programs are expected to be financed primarily from internal sources. Short-term debt will be utilized when 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.
FOREIGN UTILITY OPERATIONS
During 1993, The Southern Company made investments of approximately $315 million in utilities that own and operate generating facilities in various foreign markets. The consolidated financial statements reflect these investments in majority-owned subsidiaries on a consolidated basis and other investments on an equity basis.
BANK CREDIT ARRANGEMENTS
At the beginning of 1994, unused credit arrangements with banks totaled $1.1 billion, of which approximately $500 million expires at various times during 1994 and 1995; $130 million expires at May 1, 1996; $400 million expires at June 30, 1996; and $70 million expires at December 1, 1996.
Georgia Power's revolving credit agreements of $150 million, of which $130 million remained unused as of December 31, 1993, expire May 1, 1996. 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.
The $400 million expiring June 30, 1996, 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 $70 million of revolving credit agreements expiring December 1, 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 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 has $20 million of revolving credit arrangements expiring December 31, 1995. These agreements allow short-term borrowings to be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at 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.
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.
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
II-30 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
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 $15 billion at December 31, 1993. 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. The remaining unamortized amount included in deferred charges at December 31, 1993, was $70 million.
OPERATING LEASES
The operating companies have entered into coal rail car rental agreements with various terms and expiration dates. Rental expense totaled $11 million, $9 million, and $7 million for 1993, 1992, and 1991, respectively. At December 31, 1993, estimated minimum rental commitments for noncancelable operating leases were as follows:
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 two 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 entered into a joint ownership agreement with OPC with respect to the Rocky Mountain project, as discussed later.
At December 31, 1993, 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:
*Estimated ownership at date of completion.
Georgia Power and OPC have entered into 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 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. Georgia Power has held preliminary discussions with other parties regarding the potential disposition of its remaining interest in the project.
II-31 NOTES (continued) THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES 1993 ANNUAL REPORT
Alabama Power and Georgia Power have contracted to operate and maintain the jointly owned facilities -- except for the Rocky Mountain project -- 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 $183 million, $289 million, and $320 million, for 1993, 1992, and 1991, respectively. Projected capacity payments for the next five years are as follows: $132 million in 1994; $77 million in 1995; $70 million in 1996; $59 million in 1997; and $59 million in 1998. 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, $100 million in 1992, and $30 million in 1991. The projected net amount to be deferred in 1994 is $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. PLANNED SALES OF INTEREST IN PLANT SCHERER
Georgia Power has completed two 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 $806 million, including any gains on these transactions. FP&L would eventually own approximately 76.4 percent of the unit, with JEA owning the remainder. The capacity from this unit was previously dedicated to long-term power sales contracts with Gulf States that were suspended in 1988. Georgia Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
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
GENERAL
The operating subsidiaries 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. Certain of these agreements are non-firm and are based on capacity of the system in general. Other agreements are firm and pertain to capacity related to specific generating units. Because the energy is generally sold at cost under these agreements, revenues from capacity sales primarily affect profitability. The capacity revenues have been as follows:
Long-term non-firm power of 400 megawatts was sold in 1993 to Florida Power Corporation (FPC). In January 1994, this amount decreased to 200 megawatts, and the contract will expire at year-end.
Unit power from specific generating plants is currently being sold to FP&L, FPC, JEA, and the city of Tallahassee, Florida. Under these agreements, an average
II-32 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
of 1,700 megawatts of capacity is scheduled to be sold during 1994 and 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.
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, subsidiaries of The Southern Company entered into a settlement agreement with Gulf States that resolved litigation between the companies that had been pending since 1986 and arose out of a dispute over certain unit power and other long-term power sales contracts. In 1993, all remaining terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received -- less the amounts to be refunded to customers and the amounts previously included in income -- The Southern Company recorded an increase in consolidated net income of $114 million, or 18 cents per share, in November 1991. With respect to Alabama Power's portion of proceeds received in 1991, see Note 3 concerning the regulatory treatment of amounts being refunded to retail customers over a three-year period.
9. INCOME TAXES
Effective January 1, 1993, The Southern Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption of Statement No. 109 resulted in cumulative adjustments that had no material effect on consolidated net income. The adoption also resulted in the recording of additional deferred income taxes and related assets and liabilities. The related assets of $1.5 billion are revenues to be received from customers. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. The related liabilities of $1.1 billion are revenues to be refunded to customers. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Additionally, deferred income taxes related to accelerated tax depreciation previously shown as a reduction to utility plant were reclassified.
Details of the federal and state income tax provisions are as follows:
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:
II-33 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
Deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the Consolidated Statements of Income. Credits amortized in this manner amounted to $29 million in 1993, $41 million in 1992, and $48 million in 1991. At December 31, 1993, 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:
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 have been adjusted to reflect the stock distribution.
SHARES RESERVED
At December 31, 1993, a total of 24 million shares was reserved for issuance pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee Savings 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, 34 employees are eligible to participate in the plan. As of December 31, 1993, 38 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, such that all options generally are exercisable by 1997. Options outstanding will expire upon termination of the plan, which will occur on December 7, 1997, unless terminated earlier by the board of directors. Stock option activity in 1992 and 1993 is summarized below:
II-34 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
11. OTHER LONG-TERM DEBT
Details of other long-term debt are as follows:
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 $217 million and $236 million at December 31, 1993 and 1992, respectively. At December 31, 1993, the composite interest rates for nuclear fuel, buildings, and other were 3.6 percent, 9.7 percent, and 12.0 percent, respectively. Sinking fund requirements and/or serial maturities through 1998 applicable to other long-term debt are as follows: $89 million in 1994; $154 million in 1995; $58 million in 1996; $26 million in 1997; and $7 million in 1998.
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 is as follows:
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.
II-35 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
13. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The act limits to $9.4 billion public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. A company could be assessed up to $79 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power -- based on its ownership and buyback interests -- is $159 million and $171 million, respectively, per incident but not more than an aggregate of $20 million and $22 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 adjustment in the event that losses exceed accumulated reserve funds. Alabama Power's and Georgia Power's maximum annual assessments are limited to $14 million and $18 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, and American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters.
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 $2.3 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 $16 million and $15 million, respectively. The replacement power assessments are $9 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 $6 million and $7 million, respectively.
II-36 NOTES (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
14. COMMON STOCK DIVIDEND RESTRICTIONS
The income of The Southern Company is derived primarily from equity in earnings of its operating subsidiaries. At December 31, 1993, $1.6 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.
15. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 1993 and 1992 are as follows:
*Common stock data have been 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.
The company's business is influenced by seasonal weather conditions and the timing of rate changes.
II-37 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The Southern Company and Subsidiary Companies 1993 Annual Report (See Note Below)
Note: Common stock data have been 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.
II-38 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The Southern Company and Subsidiary Companies 1993 Annual Report (See Note Below)
II-39 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
II-40 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued) The Southern Company and Subsidiary Companies 1993 Annual Report
II-41 CONSOLIDATED STATEMENTS OF INCOME The Southern Company and Subsidiary Companies
II-42
CONSOLIDATED STATEMENTS OF INCOME The Southern Company and Subsidiary Companies
II-43
CONSOLIDATED STATEMENTS OF CASH FLOWS The Southern Company and Subsidiary Companies
II-44
CONSOLIDATED STATEMENTS OF CASH FLOWS The Southern Company and Subsidiary Companies
II-45
CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
II-46
CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
II-47
CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
II-48
CONSOLIDATED BALANCE SHEETS The Southern Company and Subsidiary Companies
II-49
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-50
MANAGEMENT'S REPORT Alabama Power Company 1993 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 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 /s/ William B. Hutchins, III - -------------------------- ------------------------------ Elmer B. Harris William B. Hutchins III President Senior Vice President and Chief Executive Officer and Chief Financial Officer
II-51
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, 1993 and 1992, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. 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-59 through II-77) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 1993 and 1992, 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 & Co.
Birmingham, Alabama February 16, 1994
II-52 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
The company's 1993 net income after dividends on preferred stock was $346 million, representing a 2.3 percent increase over the prior year. This improvement can be attributed to higher retail energy sales and lower financing costs. Retail energy sales increased 5.1 percent from 1992 levels. This was primarily due to the extreme weather during 1993, especially when compared to the unusually mild weather of 1992. Long-term debt interest expense and preferred stock dividends decreased in 1993 reflecting the continued redemption and refinancing of higher cost debt and preferred stock. These positive factors were partially offset by higher operating costs and a scheduled reduction in capacity sales to non-affiliated utilities.
When comparing 1992 earnings with the prior year, it should be noted that 1991 earnings included an unusual item -- the settlement of litigation with Gulf States Utilities Company (Gulf States) that resulted in an after-tax gain of $9 million. A comparison of 1992 to 1991, excluding this unusual item, would reflect a 1992 increase in earnings of $8 million.
The return on average common equity for 1993 was 13.9 percent compared to 14.0 percent in 1992, and 14.6 percent in 1991.
REVENUES
The following table summarizes the principal factors that affected operating revenues for the past three years:
Retail revenues of $2.4 billion in 1993 increased $180 million (8.0 percent) over the prior year, compared with no increase in 1992. The extreme weather during 1993 and sales growth contributed to the increase in retail revenues over 1992. Fuel revenues increased substantially during 1993. However, changes in fuel revenues are offset with corresponding changes in recoverable fuel expenses and have no effect on net income. Gains in 1992 retail revenues, due to higher rates and sales growth, were partially offset by lower fuel cost recovery revenues.
Revenues from sales to non-affiliated utilities 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:
II-53 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1993 Annual Report
Capacity revenues decreased in 1993 due to a scheduled reduction in capacity dedicated to unit power sales customers for the first five months of the year. The major factor contributing to the increase in capacity revenues in 1992 and 1991 was a new generating unit, Plant Miller Unit 4, that was placed in commercial service in March 1991 and dedicated to unit power sales. This unit's fixed costs are higher than those of the unit it replaced, which previously provided energy to unit power sales customers.
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.
Kilowatt-hour (KWH) sales for 1993 and the percent change by year were as follows:
EXPENSES
Total operating expenses of $2.4 billion for 1993 were up 7.0 percent compared with the prior year. The increase was mainly attributable to higher production expenses of $95 million to meet increased energy demands.
Total operating expenses for 1992 increased moderately over those recorded in 1991. However, absent the Gulf States settlement, which reduced 1991 operating expenses, total operating expenses would have decreased $6 million.
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 increases in 1993 represent $83 million of the production expense increase mentioned above. Fuel expense decreased in 1992 as a result of the reduction in the cost of both coal and nuclear fuel, offset somewhat by a small increase in generation. Fuel cost per kilowatt-hour generated was 1.73 cents in 1993, 1.64 cents in 1992 and 1.69 cents in 1991. Purchased power expenses decreased in 1992 primarily due to less purchased energy and a decrease in the price of such energy.
Other operation expenses increased 6.0 percent in 1993 following a minimal increase in 1992. The increase in 1993 is 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.
Depreciation and amortization expense increased 3.4 percent in 1993 and 3.5 percent in 1992. This is principally due to continued growth in depreciable plant in service. Taxes other than income taxes increased 4.0 percent in 1993 and 1.4 percent in 1992. These increases were the result of the addition of new facilities and higher revenue-related taxes.
The increase in income tax expense of 2.6 percent for 1993 is primarily attributable to a one percent increase in the corporate federal income tax rate effective January 1, 1993.
Interest expense and dividends on preferred stock decreased $7.5 million (2.8 percent) and $7.2 million (2.6 percent) in 1993 and 1992, respectively. These reductions are due to significant refinancing of long-term debt and preferred stock.
II - 54
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1993 Annual Report
EFFECTS OF INFLATION
The company is subject to rate regulation that is based on the recovery of historical costs and, therefore is subject to economic losses caused by inflation. 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 regulatory matters.
Future earnings in the near term will also 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. In addition, the Energy Policy Act of 1992 (Energy Act) will have a profound 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 law also includes provisions to streamline the licensing process for new nuclear plants. The company is preparing to meet the challenge of this major change in the traditional business practices 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, and 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, pressure for legislation to allow retail wheeling will continue. If the company does not remain a low-cost producer and provide quality service, the company's retail energy sales growth, as well as any new long-term contracts for energy sales outside the service area, could be limited, and this could significantly erode earnings.
Rates to retail customers served by the company are regulated by the Alabama Public Service Commission (APSC). Rates for the company can be adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return. See Note 3 to the financial statements for information about other regulatory matters.
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 reduce earnings if such costs are not fully recovered. The Clean Air Act is discussed later under "Environmental Matters."
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112, Employers' Accounting for Postemployment Benefits, which must be effective by 1994. The new standard requires that all types of benefits provided to former or inactive employees and their families prior to retirement be accounted for on an accrual basis. These benefits include salary continuation, severance pay, supplemental unemployment benefits, disability-related benefits, job training, and health and life insurance coverage. In 1993, the company adopted Statement No. 112, with no material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which is effective in 1994. Statement No. 115 supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities. The company adopted the new rules January 1, 1994, with no material effect on the financial statements.
II-55 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1993 Annual Report
FINANCIAL CONDITION
OVERVIEW
The company's financial condition remained stable in 1993. Growth in energy sales 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 contributed to this stability.
The company had gross property additions of $436 million in 1993. The majority of funds needed for gross property additions since 1990 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.
On January 1, 1993, the company changed its methods of accounting for postretirement benefits other than pensions, and for income taxes. See Notes 2 and 8 to the financial statements, regarding the impact of these changes.
CAPITAL STRUCTURE
The company's ratio of common equity to total capitalization was 47.4 percent in 1993, compared with 47.6 percent in 1992, and 45.4 percent in 1991.
In 1993, the company issued $860 million of first mortgage bonds, $158 million of preferred stock and, through public authorities, $144 million of pollution control revenue bonds. The company continued to reduce financing costs by retiring higher-cost bonds and preferred stock. Retirements, including maturities, of bonds totaled $835 million, and preferred stock retirements totaled $207 million. Composite financing rates as of year-end for 1991 through 1993 were as follows:
The company's current securities ratings are as follows:
CAPITAL REQUIREMENTS
Capital expenditures are estimated to be $588 million for 1994, $572 million for 1995, and $531 million for 1996. The total is $1.7 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; increasing costs of labor, equipment, and materials; and the cost of capital.
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.
In addition to the funds needed for the capital budget, approximately $80 million will be required by the end of 1996 for present sinking fund requirements, redemptions announced, and maturities of first mortgage bonds. Also, the company plans to continue a program 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 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 must be implemented in 1995 and affects eight generating plants -- some 10,000
II-56 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1993 Annual Report
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.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate 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 allocating 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 market for emission allowances is developing slower than expected. However, The Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, and this has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment would be installed on all fossil-fired units. Under this Phase I compliance approach, additional construction expenditures are estimated to total approximately $275 million through 1995 for The Southern Company, of which the company's portion is approximately $30 million.
Phase II compliance costs are expected to be higher because requirements are stricter and all fossil-fired generating plants are affected. For 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 construction expenditures ranging from approximately $450 million to $800 million for The Southern Company, of which the company's portion is approximately $225 million to $350 million. However, the full impact of Phase II compliance cannot now be determined with certainty, pending the 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 cost of compliance for both Phase I and Phase 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.
There can be no assurance that all Clean Air Act costs will be recovered.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The study will serve as the basis for 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 is expected to take some action on this issue in 1994. 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
II-57 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 1993 Annual Report
and cannot be determined at this time.
In 1994 or 1995, the EPA is expected to issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
The company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the company could incur costs to clean up properties currently or previously owned. The company conducts studies to determine the extent of any required clean-up costs and has recognized in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are in the process of being reauthorized or amended by Congress. These include: the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; and the Resource Conservation and Recovery 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 electric system. 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
It is anticipated that the funds required will be derived from sources in form and quantity similar to those used in the past. To issue additional first mortgage bonds and preferred stock, the company must comply with certain earnings coverage requirements designated in its mortgage indenture and corporate charter. The company's coverages are at a level that would permit any necessary amount of security sales at current interest and dividend rates.
As required by the Nuclear Regulatory Commission and as ordered by the APSC, the company has established external trust funds for nuclear decommissioning costs. Also, during 1993, the APSC issued a policy statement which will require external funding of postretirement benefits. The cumulative effect of funding these items over a long period will diminish internally funded capital and may require capital from other sources. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning."
II-58 STATEMENTS OF INCOME For the Years Ended December 31, 1993, 1992, and 1991 Alabama Power Company
The accompanying notes are an integral part of these statements.
II-59
STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993, 1992, and 1991 Alabama Power Company
( ) Denotes use of cash. The accompanying notes are an integral part of these statements.
II-60
BALANCE SHEETS At December 31, 1993 and 1992 Alabama Power Company
The accompanying notes are an integral part of these statements.
II-61 BALANCE SHEETS At December 31, 1993 and 1992 Alabama Power Company
The accompanying notes are an integral part of these statements.
II-62 STATEMENTS OF CAPITALIZATION At December 31, 1993 and 1992 Alabama Power Company
The accompanying notes are an integral part of these statements.
II-63 STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993, 1992, and 1991 Alabama Power Company
The accompanying notes are an integral part of these statements.
II-64
NOTES TO FINANCIAL STATEMENTS Alabama Power Company 1993 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, a system service company, Southern Electric International (Southern Electric), Southern Nuclear Operating Company (Southern Nuclear), and various other subsidiaries related to foreign utility operations and domestic non-utility operations. At this time, the operations of the other subsidiaries are not material. 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 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.
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 commissions.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The company accrues revenues for services rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The company's electric rates include provisions to adjust billings for fluctuations in fuel and the energy component of purchased power costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates.
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 $62 million in 1993, $48 million in 1992, and $69 million in 1991. 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 currently estimates its liability under this law to be approximately $46 million. This obligation is recognized in the accompanying Balance Sheets.
DEPRECIATION AND NUCLEAR DECOMMISSIONING
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates which approximated 3.3 percent in 1993, 1992, and 1991. 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.
II-65 NOTES (continued) Alabama Power Company 1993 Annual Report
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. Reasonable assurance may be in the form of an external trust fund, a surety method, or prepayment. The company has established external trust funds to comply with the NRC's regulations. Prior to the enactment of these regulations, the company had reserved nuclear decommissioning costs. 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 amount prescribed by the NRC.
The estimated cost of decommissioning and the amounts being recovered through rates at December 31, 1993, for Plant Farley were as follows:
The amount in the internal reserve is being transferred into the external trust funds over the remaining life of the license for Plant Farley as approved by the APSC.
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 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.
In years prior to 1993, income taxes were accounted for and reported under Accounting Principles Board Opinion No. 11. Effective January 1, 1993, the company adopted Financial Accounting Standards Board (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, net of deferred income tax, was 6.2 percent in 1991. Such method of computing AFUDC ceased upon the commercial operation of Plant Miller Unit 4 in March 1991. For construction projects begun after 1986, deferral of taxes related to capitalized interest is no longer permitted. For those projects, the composite rate used to determine the amount of allowance was 7.8 percent in 1993, 7.9 percent in 1992, and 8.3 percent in 1991. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 1.5 percent in 1993, 1.1 percent in 1992, and 2.0 percent in 1991.
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 replacements of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive
II-66 NOTES (continued) Alabama Power Company 1993 Annual Report
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, 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:
The fair values of nuclear decommissioning trusts and investment securities were based on listed closing market prices. 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
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 future recoverability of this cost. The amount was $23 million and $22 million at December 31, 1993 and 1992, respectively. In 1994, an estimated 65 percent of the 1993 deferred vacation cost will be expensed and the balance will be charged to construction and other accounts.
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 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.
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 has been established for funding amounts to the extent deductible under federal income tax regulations. Amounts funded are primarily invested in debt and equity securities. Accrued costs of life insurance benefits, other than current cash payments for retirees, currently are not being funded. However, in December 1993, the APSC issued an accounting policy statement which requires the company to externally fund all postretirement benefits. It is expected that an external funding program will begin in 1994.
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."
II-67 NOTES (continued) Alabama Power Company 1993 Annual Report
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 and 1991 were $15.2 million and $15.4 million, respectively.
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. Retiree medical and life insurance information is shown only for 1993 because Statement No. 106 was adopted as of January 1, 1993, on a prospective basis. The funded status of the plans at December 31 was as follows:
The weighted average rates assumed in the actuarial calculations were:
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 11.3 percent for 1993, 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 by 1.0 percent would increase the accumulated medical benefit obligation as of December 31, 1993, by $32.8 million and the aggregate of the service and interest cost components of the net retiree medical cost by $3.4 million.
II-68
NOTES(continued) Alabama Power Company 1993 Annual Report
Components of the plans' net cost are shown below:
Of the above net pension amounts, $(8.9) million in 1993, $(5.1) million in 1992, and $0.7 million in 1991 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Of the above net postretirement medical and life insurance costs recorded in 1993, $22 million was charged to operating expenses and the remainder was charged to construction and other accounts.
WORK FORCE REDUCTION PROGRAM
The company has incurred additional costs for work force reduction programs. The costs related to these programs were $16.1 million, $13.4 million and $6.7 million for the years 1993, 1992 and 1991, 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 $15.3 million at December 31, 1993.
3. LITIGATION AND REGULATORY MATTERS
RETAIL RATE ADJUSTMENT PROCEDURES
In November 1982, the APSC adopted rates that provide for periodic adjustments based upon the company's earned return on end-of-period retail common equity. The rates also provide for adjustments to recognize the placing of new generating facilities in retail service. Both increases and decreases have been placed into effect since the adoption of these rates. The rate adjustment procedures allow a return on common equity range of 13.0 percent to 14.5 percent and limit increases or decreases in rates to 4 percent in any calendar year.
The APSC issued an order in December 1991 that reduced a scheduled 2.03 percent annual increase in rates to 1.03 percent, effective January 1992. The 1 percent reduction will remain in effect through 1994. The rate reduction was designed to refund to retail ratepayers a portion of the benefits from a settled contract dispute with Gulf States Utilities Company (Gulf States). The present value of this portion of the settlement amounting to approximately $60 million is being amortized to revenues to offset the rate reduction in accordance with the APSC's rate order. See Note 7 for additional information concerning the Gulf States settlement.
Also in the December 1991 rate order, the APSC reaffirmed its satisfaction with the ratemaking mechanism and stated that it did not foresee any further review or changes in the procedures until after 1994. The ratemaking procedures will remain in effect after 1994 unless the APSC votes to modify or discontinue them.
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.
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
II-69 NOTES(continued) Alabama Power Company 1993 Annual Report
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 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 occur as a result of this proceeding would be effective 60 days after a proper notice of the proceeding is published. A notice was published on May 10, 1991.
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.
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 company's financial statements.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $588 million in 1994, $572 million in 1995 and $531 million in 1996. The estimates include AFUDC of $10 million in 1994, $11 million in 1995 and $12 million in 1996. The estimates for property additions for the three-year period includes $36.5 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, 1993, 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 when necessary; the amounts available are discussed below. The company may issue additional long-term debt and preferred stock primarily for the purposes of debt maturities and for redeeming higher-cost securities.
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
II-70 NOTES(continued) Alabama Power Company 1993 Annual Report
company's primary sources of external financing are sales of first mortgage bonds and preferred stock to the public, receipt of additional paid-in capital from The Southern Company, and leasing of nuclear material. In order to issue additional first mortgage bonds and preferred stock, the company must comply with certain earnings coverage requirements contained in its mortgage indenture and corporate charter. The most restrictive of these provisions requires, for the issuance of additional first mortgage bonds, that before-income-tax earnings, as defined, cover pro forma annual interest charges on outstanding first mortgage bonds at least twice; and for the issuance of additional preferred stock, that gross income available for interest cover pro forma annual interest charges and preferred stock dividends at least one and one-half times. These coverages, for first mortgage bonds and for preferred stock for the year ended December 31, 1993, were 5.70 and 2.71, respectively.
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, 1996. 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 $350 million which expire at various times during 1994 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.
In connection with all other lines of credit, the company has the option of paying fees or maintaining compensating balances, which are substantially all the cash of the company except for daily working funds and similar items. These balances are not legally restricted from withdrawal.
At December 31, 1993, the company had regulatory approval to have outstanding up to $450 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 the year 2013 were approximately $8 billion at December 31, 1993.
In addition, a contract with a certain coal contractor requires reimbursement or purchase, at net book value, of the investment in the mine or equipment upon termination of the contract. At December 31, 1993, such net book value was approximately $13 million. Additional commitments for coal and for nuclear fuel will be required in the future to supply the company's fuel needs.
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 expiring in 1994 which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense
II-71 NOTES(continued) Alabama Power Company 1993 Annual Report
and a return on equity, whether or not SEGCO has any capacity and energy available. The company's share of expenses totaled $86 million in 1993, $73 million in 1992 and $82 million in 1991, and is included in "Purchased power from affiliates" in the Statements of Income. An amended contract has been filed with the FERC with substantially the same provisions, but the term thereof would be extended automatically for two year periods, subject to any party's right to cancel upon two years' notice.
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, 1993, the capitalization of SEGCO consisted of $58 million of equity and $84 million of long-term debt on which the annual interest requirement is $3.8 million. SEGCO paid dividends totaling $11.3 million in 1993, $12.0 million in 1992, and $4.5 million in 1991, of which one-half of each was paid to the company. SEGCO's net income was $8.3 million, $9.3 million and $9.2 million for 1993, 1992 and 1991, respectively.
In June 1992 the company completed the sale of a portion of Plant Miller Units 1 and 2 to Alabama Electric Cooperative, Inc. (AEC). The company's percentage ownership and investment in jointly-owned generating plants at December 31, 1993, follows:
(1) Jointly owned with an affiliate, Mississippi Power Company. (2) Jointly owned with AEC.
7. LONG-TERM POWER SALES AGREEMENTS
GENERAL
The operating subsidiaries of The Southern Company, including the company, have entered into long-term and short-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. Certain of these agreements are non-firm and are based on capacity of the system in general. Other agreements are firm and pertain to capacity related to specific generating units. Because the energy is generally sold at cost under these agreements, revenues from capacity sales primarily affect profitability. The company's portion of off-system capacity revenues has been as follows:
Long-term non-firm power of 400 megawatts was sold by the Southern electric system in 1993 to Florida Power Corporation (FPC). In January 1994, this amount decreased to 200 megawatts, and the contract will expire at year-end.
Unit power from Plant Miller is being sold to FPC, Florida Power & Light Company (FP&L), Jacksonville Electric Authority (JEA) and the City of Tallahassee, Florida (Tallahassee). Under these agreements, an average of 1,100 megawatts of capacity is scheduled to be
II-72 NOTES(continued) Alabama Power Company 1993 Annual Report
sold during 1994. Thereafter, these sales will increase to some 1,200 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.
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, subsidiaries of The Southern Company entered into a settlement agreement with Gulf States that resolved litigation between the companies that had been pending since 1986 and arose out of a dispute over certain unit power and other long-term power sales contracts. In 1993, all remaining terms and obligations of the settlement agreement were satisfied.
With respect to the company's portion of proceeds received in 1991, see Note 3 concerning the regulatory treatment of amounts being refunded to retail customers over a three-year period.
ALABAMA MUNICIPAL ELECTRIC AUTHORITY (AMEA) CAPACITY CONTRACTS
In August 1986, the company entered into a firm power purchase contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for a period of 15 years commencing September 1, 1986 (1986 Contract). In October 1991, the company entered into a second firm power purchase contract with AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80 megawatts) for a period of 15 years commencing October 1, 1991 (1991 Contract). In both contracts the power will be sold to AMEA for its member municipalities that previously were served directly by the company as wholesale customers. Under the terms of the contracts, the company received payments from AMEA representing the net present value of the revenues associated with the respective capacity entitlements, discounted at effective annual rates of 9.96 percent and 11.19 percent for the 1986 and 1991 Contracts, respectively. These payments are being recognized as operating revenues and the discounts are being amortized to other interest expense as scheduled capacity is made available over the terms of the contracts.
In order to secure AMEA's advance payments and the company's performance obligation under the contracts, the company issued and delivered to an escrow agent first mortgage bonds representing the maximum amount of liquidated damages payable by the company in the event of a default under the contracts. No principal or interest is payable on such bonds unless and until a default by the company occurs. As the liquidated damages decline under the contracts, a portion of the bonds equal to the decreases are returned to the company. At December 31, 1993, $153 million of such bonds were 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 of Statement No. 109 resulted in cumulative adjustments that had no material effect on net income. The adoption also resulted in the recording of additional deferred income taxes and related assets and liabilities. The related assets of $469 million are revenues to be received from customers. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. The related liabilities of $441 million are revenues to be refunded to customers. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Additionally, deferred income taxes related to accelerated tax depreciation previously shown as a reduction to utility plant were reclassified.
II-73 NOTES (continued) Alabama Power Company 1993 Annual Report
Details of the federal and state income tax provisions are as follows:
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:
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 1993, $18 million in 1992, and $16 million in 1991. At December 31, 1993, 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:
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.
II-74 NOTES (continued) Alabama Power Company 1993 Annual Report
9. OTHER LONG-TERM DEBT
Details of other long-term debt are as follows:
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 $154.5 million of such pollution control obligations, the company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.
The company has capitalized leased nuclear material and recorded the related lease obligations. The arrangement provides for the payment of interest at varying rates and times dependent on options selected by the company from types of loans available under the arrangement. At the end of 1993 the effective rate of this lease arrangement, including applicable fees, was 3.58 percent. Principal payments are required under the arrangement based on the cost of fuel burned.
The company has also capitalized certain office building leases and a street light lease. Monthly principal payments plus interest are required, and at December 31, 1993, the interest rate was 9.5 percent for office buildings and 13.0 percent for street lights.
The net book value of capitalized leases included in utility plant in service was $94.7 million and $103.0 million at December 31, 1993 and 1992, respectively. The estimated aggregate annual maturities of other long-term debt through 1998 are as follows: $38.9 million in 1994, $33.3 million in 1995, $18.7 million in 1996, $6.4 million in 1997 and $3.0 million in 1998.
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:
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 1994 requirement of $20.1 million was satisfied by the deposit of cash in 1994, which was used for the partial redemption of various series of outstanding bonds. In addition, maturing in 1994 are other long-term debt of $38.9 million consisting primarily of capitalized nuclear fuel obligations.
II-75 NOTES (continued) Alabama Power Company 1993 Annual Report
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 limits to $9.4 billion, 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 adjustment in the event that losses exceed accumulated reserve funds. The company's maximum annual assessment per incident is limited to $14 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, and American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters.
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 $2.3 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The maximum annual assessments per incident under current policies for the company would be $16 million for excess property damage and $9 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.
II-76 NOTES (continued) Alabama Power Company 1993 Annual Report
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, 1993, $653 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 1993 and 1992 are as follows:
The company's business is influenced by seasonal weather conditions and the timing of rate adjustments.
II-77 SELECTED FINANCIAL AND OPERATING DATA Alabama Power Company
II-78 SELECTED FINANCIAL AND OPERATING DATA Alabama Power Company
II-79 SELECTED FINANCIAL AND OPERATING DATA (continued) Alabama Power Company
Notes: (1) Generating capacity and fuel data includes Alabama Power Company's 50% portion of SEGCO. (2) Includes Southeastern Power Administration allotment. * Less than one-tenth of one percent.
II-80 SELECTED FINANCIAL AND OPERATING DATA (continued) Alabama Power Company
II-81
STATEMENTS OF INCOME Alabama Power Company
* Includes the effect of recognizing, beginning in 1987, retail service rendered but not yet billed to customers.
II-82
STATEMENTS OF INCOME Alabama Power Company
II-83 STATEMENTS OF CASH FLOWS Alabama Power Company
( ) Denotes use of cash.
II-84
STATEMENTS OF CASH FLOWS Alabama Power Company
II-85
BALANCE SHEETS Alabama Power Company
*Includes the effect of recognizing, beginning in 1987, retail service rendered but not yet billed to customers.
II-86
BALANCE SHEETS Alabama Power Company
II-87
BALANCE SHEETS Alabama Power Company
*Includes the effect of recognizing, beginning in 1987, retail service rendered but not yet billed to customers.
II-88
BALANCE SHEETS Alabama Power Company
II-89
ALABAMA POWER COMPANY OUTSTANDING SECURITIES AT DECEMBER 31, 1993 FIRST MORTGAGE BONDS
II-90
ALABAMA POWER COMPANY
SECURITIES RETIRED DURING 1993
FIRST MORTGAGE BONDS
II-91 GEORGIA POWER COMPANY
FINANCIAL SECTION
II-92
MANAGEMENT'S REPORT Georgia Power Company 1993 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 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 regulatory proceedings are concluded. 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 /s/ Warren Y. Jobe - --------------------- -------------------------- H. Allen Franklin Warren Y. Jobe President and Chief Executive Vice President, Executive Officer Treasurer and Chief Financial Officer
II-93 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) as of December 31, 1993 and 1992, 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, 1993. 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-102 through II-122) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 1993 and 1992, 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 the recoverability of the Company's investment in the Rocky Mountain pumped storage hydroelectric project. The outcome of this uncertainty cannot be determined until regulatory proceedings are concluded. 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 & Co.
Atlanta, Georgia February 16, 1994
II-94 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
Georgia Power Company's 1993 earnings totaled $570 million, representing a $49 million (9.5 percent) increase over the prior year. This improvement is primarily a result of higher retail revenues and lower financing costs. Also, during the period, the Company had an $18 million after-tax gain on the sale of a portion of Plant Scherer Unit 4. Higher retail revenues reflect growth in energy sales of 6.1 percent from 1992 levels primarily due to exceptionally hot summer weather during 1993. Interest expense and preferred stock dividends decreased in 1993 due to the redemption and refinancing of higher-cost debt and preferred stock. These positive events were partially offset by higher operating expenses.
In comparing 1992 earnings to the prior year, it should be noted that 1991 earnings included two unusual items that significantly affect this comparison. Earnings in 1991 were $89 million higher due to the completion of a settlement agreement with Gulf States Utilities Company (Gulf States) related to power sales contracts. This increase was partially offset by an after-tax charge of $33 million in 1991 for a work force reduction program. A comparison of 1992 to 1991 -- excluding these unusual items -- would reflect a 1992 increase in earnings of $102 million.
REVENUES
The following table summarizes the factors impacting operating revenues for the 1991-1993 period:
Retail revenues of $3.8 billion in 1993 increased $262 million (7.4 percent) over the prior year, compared with an increase of $87 million (2.5 percent) in 1992. The exceptionally hot weather during the summer of 1993 was the primary factor affecting the increase in retail revenues over 1992. The increase in retail revenues for 1992 was a result of higher retail rates and sales growth, partially offset by mild weather and lower fuel revenues. 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 options programs generally represent the direct recovery of program costs. See Note 3 to the financial statements for further information on these programs.
Revenues from sales to non-affiliated utilities decreased in both 1993 and 1992. Contractual unit power sales to Florida utilities for 1993 and 1992 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 July 1991 and June
II-95 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1993 Annual Report
1993. Sales to municipalities and cooperatives increased slightly in 1993 due to the hot summer weather. Generally, these sales have been decreasing as these customers retain more of their own generation at facilities jointly owned with the Company.
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:
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.
Changes in revenues are a function of the amount of energy sold each year. Kilowatt-hour (KWH) sales for 1993 and the percent change by year were as follows:
The hot summer weather during 1993 contributed primarily to the sales growth in the residential and commercial classes. Continued improvement in economic conditions positively impacted sales growth in the commercial and industrial classes. Residential energy sales growth in 1992 reflected mild weather. Commercial and industrial sales growth in 1992 is attributable to improved economic conditions.
The decrease in energy sales to non-affiliated utilities reflects scheduled reductions in contractual power sales.
EXPENSES
Fuel expense increased 2.3 percent in 1993 due to higher generation, which was partially offset by lower nuclear fuel costs. In 1992, fuel expense decreased 6.9 percent due to lower generation and lower fuel costs. Purchased power expense has decreased significantly since 1991, reflecting declining contractual capacity purchases from the co-owners of plants Vogtle and Scherer. Purchased power expense decreased $88 million in 1993 and $43 million in 1992. The declines in Plant Vogtle contractual capacity purchases did not have a significant impact on earnings in 1993 or 1992 as 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 for additional information.
Other Operation and Maintenance (O & M) expenses increased 9.0 percent in 1993 after remaining relatively flat in 1992. The increase in 1993 is primarily the result of environmental remediation costs at various current and former operating sites, the one- time costs of an 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 for additional information concerning these new rules. Also, during 1993, O & M expenses reflect costs associated with new demand-side option programs. These costs were offset by increases in retail revenues. See Note 3 to the financial statements for additional information on the recovery of demand-side option program costs.
Depreciation and amortization expense increased slightly due to additional plant investment. The 1992 decrease is due to the effects of lower depreciation rates effective in October 1991. Taxes other than income taxes increased 7.4 percent in 1993 and 3.8 percent in 1992.
II-96
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1993 Annual Report
These increases reflect higher ad valorem taxes. The 1993 increase also includes higher taxes paid to municipalities as a result of increased sales.
Income tax expense increased $62 million in 1993 due primarily to higher earnings and the effect of a one percent increase in the federal tax rate effective January, 1993. Also, the Company incurred $27 million of tax expense in connection with the second in a series of four separate transactions to sell Plant Scherer Unit 4. The sale resulted in an after-tax gain of $18 million.
Interest expense and dividends on preferred stock decreased $19 million (4.0 percent) and $49 million (9.3 percent) in 1993 and 1992, respectively. These reductions are due to significant refinancing of long-term debt and preferred stock. The Company refinanced $1.7 billion of securities in both 1993 and 1992. In addition, the Company has retired $544 million of long-term debt with the proceeds from the 1991 and 1993 Plant Scherer Unit 4 sales. Other interest charges in 1993 include interest related to the settlement of an Internal Revenue Service audit. The settlement, in total, did not have an 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 ranging from growth in energy sales to 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 1994 through 1996.
The scheduled addition of four combustion turbine generating units in 1994, four units in 1995 and one unit in 1996, as well as the Rocky Mountain pumped storage hydroelectric project in 1995, will increase related O & M and depreciation expenses. See Note 4 to the financial statements for information on regulatory uncertainties related to the Rocky Mountain project. The GPSC has certified the construction of the 1994 and 1995 combustion turbine generating units for meeting peak generating needs. In addition, the Company has completed a demonstration competitive bidding process for its supply-side requirements expected for 1996. The Company has filed with the GPSC for certification of a four-year purchase power agreement beginning in 1996, and for construction of a jointly owned combustion turbine to be completed in 1996 to meet these needs.
As part of efforts to curtail growth in operating expenses, the Company is reducing its work force through an early-retirement program announced in January 1994. The program resulted in a first quarter 1994 after-tax charge to earnings of $39 million. The program has an expected payback period of approximately two years.
Pursuant to an Integrated Resource Plan approved by the GPSC in 1992, the Company has implemented various demand-side option programs and has been authorized by the GPSC to recover associated program costs through rate riders. On October 15, 1993, a superior court judge ruled that recovery of these costs through rate riders is unlawful. The Company has ceased collection of the rate riders and is deferring program costs as ordered by the
II-97 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1993 Annual Report
GPSC pending the final outcome of this matter. See Note 3 to the financial statements for additional information.
The Company has completed two in a series of four separate transactions to sell Unit 4 of Plant Scherer to two Florida utilities. The remaining transactions are scheduled to take place in 1994 and 1995. If the sales take place as planned, the Company would realize an additional after-tax gain estimated to total approximately $20 million. See Note 5 to the financial statements for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air Act) could reduce earnings if such costs cannot be billed to customers. The Clean Air Act is discussed later under "Environmental Issues."
The Energy Policy Act of 1992 (Energy Act) will have a profound effect on the future of the electric utility industry. The Energy Act promotes energy efficiency, alternative fuel use, and increased competition among electric utilities. The law also includes provisions to streamline the licensing process for new nuclear generating plants. The Energy Act marks the beginning of a major change in the traditional business practices of selling electricity. The Energy Act allows Independent Power Producers (IPPs) and other electric suppliers access to a utility's transmission lines to sell their electricity to other utilities. This may enhance the incentives for IPPs to build cogeneration plants for the Company's large industrial and commercial customers. If the Company does not remain a low cost producer and provide quality service, the Company's sales growth could be limited and this could significantly erode earnings.
The Company continues to compete with other electric suppliers within the state. In Georgia, most new retail customers with more than 900 kilowatts of connected load may choose their electricity supplier. In addition, the bulk power market has become very competitive as utilities, IPPs and cogenerators seek to supply future capacity needs. Competition can create new business opportunities, but it increases risk and has the potential to adversely affect earnings.
The 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.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112, Employers' Accounting for Postemployment Benefits, which must be adopted by 1994. The new standard requires that all types of benefits provided to former or inactive employees and their families prior to retirement be accounted for on an accrual basis. These benefits include salary continuation, severance pay, supplemental unemployment benefits, disability-related benefits, job training, and health and life insurance coverage. In 1993, the Company adopted Statement No. 112, with no material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which will be effective in 1994. Statement No. 115 supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities. The Company adopted the new rules in January, 1994, with no material effect on the financial statements.
FINANCIAL CONDITION
OVERVIEW
The principal changes in the Company's financial condition in 1993 were gross utility plant additions of $674 million and the lowering of the cost of capital achieved through the refinancing or retirement of $1.7 billion of long-term debt and preferred stock.
On January 1, 1993, the Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes. See Notes 2 and 7 to the financial statements regarding the impact of these changes.
The funds needed for gross property additions are currently provided from operations. The Statements of Cash Flows provide additional details.
II-98 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1993 Annual Report
FINANCING ACTIVITIES
In 1993, the Company continued to lower its financing costs by issuing new securities and other debt, and retiring or repaying high-cost issues. New issues during 1991 through 1993 totaled $3.0 billion and retirement or repayment of securities totaled $4.2 billion. The retirements included the redemption of $253 million and $291 million in 1993 and 1991, respectively, of first mortgage bonds with the proceeds from the Plant Scherer Unit 4 sales. Composite financing rates for the years 1991 through 1993, as of year-end, were as follows:
The Company's current securities ratings are as follows:
* Not rated by Duff & Phelps
LIQUIDITY AND CAPITAL REQUIREMENTS
Cash provided from operations increased by $236 million in 1993, primarily due to higher retail sales, lower interest costs, decreasing capacity purchases from the co-owners of plants Vogtle and Scherer and the receipt of cash payments from Gulf States that completed the settlement of litigation.
The Company estimates that construction expenditures for the years 1994 through 1996 will total $688 million, $555 million and $629 million, respectively. The Company will continue to invest in transmission and distribution facilities and enhance existing generating plants. These expenditures also include amounts for nine combustion turbine generating units and equipment that will be required to comply with the provisions of the Clean Air Act. The Company's contractual capacity purchases will decline by $113 million over the next three years. Cash requirements for sinking fund requirements, redemptions announced, and maturities of long-term debt are expected to total $377 million during 1994 through 1996.
As a result of requirements by the Nuclear Regulatory Commission, the Company has established external sinking funds for the purpose of funding nuclear decommissioning costs. For 1994 through 1996, the amount to be funded for the Company totals $16 million annually. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Nuclear Decommissioning."
SOURCES OF CAPITAL
The Company expects to meet future capital requirements primarily using funds generated from operations and, if needed, by the issuance of new debt and equity securities, term loans, and short-term borrowings. To meet short-term cash needs and contingencies, the Company had approximately $540 million of unused credit arrangements with banks at the beginning of 1994. See Note 8 to the financial statements for additional information.
Completing the remaining two transactions for the sale of Plant Scherer Unit 4 will generate approximately $130 million in both 1994 and in 1995.
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 must be implemented in 1995 and affects eight generating plants -- some 10,000 megawatts
II-99 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1993 Annual Report
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.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate 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 allocating 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 market for emission allowances is developing slower than expected. However, The Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, and this has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment would be installed on all fossil-fired units. Under this Phase I compliance approach, Georgia Power's construction expenditures are estimated to total approximately $150 million through 1995.
Phase II compliance costs are expected to be higher because requirements are stricter and all fossil-fired generating plants are affected. For 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 Georgia Power construction expenditures ranging from approximately $150 million to $325 million. However, the full impact of Phase II compliance cannot now be determined with certainty, pending the 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 the Clean Air Act. Compliance costs include construction expenditures, increased costs for switching to low-sulfur coal, and costs related to emission allowances. There can be no assurance that all Clean Air Act costs will be recovered.
Metropolitan Atlanta is classified as a non-attainment area with regard to the ozone ambient air quality standards. Title I of the Clean Air Act requires the state of Georgia to conduct specific studies and establish new control rules by November 1994 -- 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 Company plants. Final attainment rules, based on modeling studies, could require installation of additional controls for nitrogen oxide emissions as early as 1997. Compliance with any new rules could result in significant additional costs. The 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 study will serve as the basis for 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
II-100 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 1993 Annual Report
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 is expected to take some action on this issue in 1994. 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 standards will depend on the level chosen for the standards and cannot be determined at this time.
In 1994 or 1995, the EPA is expected to 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 nonhazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either nonhazardous 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. These laws include the Comprehensive Environmental Response Compensation and Liability Act of 1980 (CERCLA or Superfund). 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 costs to clean-up known sites in the 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 Comprehensive Environmental Response, Compensation, and Liability Act; and the Resource Conservation and Recovery 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.
II-101
STATEMENTS OF INCOME For the Years Ended December 31, 1993, 1992, and 1991 Georgia Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-102
BALANCE SHEETS At December 31, 1993 and 1992 Georgia Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-103
BALANCE SHEETS At December 31, 1993 and 1992 Georgia Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-104
STATEMENTS OF CAPITALIZATION AT December 31, 1993 and 1992 Georgia Power Company 1993 Annual Report
II-105
STATEMENTS OF CAPITALIZATION At December 31, 1993 and 1992 Georgia Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-106
STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993, 1992, and 1991 Georgia Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-107
STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993, 1992, and 1991 Georgia Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-108
NOTES TO FINANCIAL STATEMENTS Georgia Power Company 1993 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), Southern Electric International (Southern Electric), and Southern Nuclear Operating Company (Southern Nuclear), and various other subsidiaries related to foreign utility operations and domestic non-utility operations. 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 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 support services for nuclear power plants in the Southern electric system.
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.
REVENUES AND FUEL COSTS
The Company accrues revenues for services rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as fuel is used. The Company is authorized by state law and FERC regulations to recover fuel costs and the fuel component of purchased energy costs through fuel cost recovery provisions, which are periodically adjusted to reflect increases or decreases in such costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates. Fuel costs were under recovered by $79 million and $4 million at December 31, 1993, and 1992, 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 cost of nuclear fuel is amortized to fuel expense based on estimated thermal units used to generate electric energy and includes a provision for the disposal of spent fuel. Total charges for nuclear fuel amortized to expense were $75 million in 1993, $84 million in 1992, and $93 million in 1991. The Company has contracted with the U.S. Department of Energy (DOE) for permanent disposal of spent fuel beginning in 1998; however, the actual year this service will begin is uncertain. Pending permanent disposition of the spent fuel, sufficient storage capacity is available at Plant Hatch into 2003 and at Plant Vogtle into 2009. 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 law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company -- based on its ownership interest -- estimates its total assessment under this law to be approximately $42 million to be paid over a 15-year period beginning in 1993. This obligation is recognized in the accompanying Balance Sheets and is being recovered through the fuel cost recovery provisions. The remaining liability at December 31, 1993, is $39 million.
II-109 NOTES (continued) Georgia Power Company 1993 Annual Report
NUCLEAR REFUELING OUTAGE COSTS
Prior to 1992, the Company expensed nuclear refueling outage costs as incurred during the outage period. Pursuant to the 1991 GPSC retail rate order, the Company began accounting for these costs on a normalized basis in 1992. Under this method of accounting, refueling outage costs are deferred and subsequently amortized to expense over the operating cycle of each unit, which is normally 18 months. Deferred nuclear outage costs were $17 million and $6 million at December 31, 1993 and 1992, respectively.
DEPRECIATION
Depreciation is provided on the cost of depreciable utility plant in service and is calculated primarily on the straight-line basis over the estimated composite service life of the property. The composite rate of depreciation was 3.1 percent in 1993 and 1992, and 3.2 percent in 1991. Effective October 1991, the Company adopted lower depreciation rates consistent with the 1991 GPSC retail rate order. When a property unit is retired or otherwise disposed of in the normal course of business, its costs and the costs of removal, less salvage, are charged to the accumulated provision for depreciation. Minor items of property included in the cost of the plant are retired when the related property unit is retired.
NUCLEAR DECOMMISSIONING
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. Reasonable assurance may be in the form of an external sinking fund, a surety method, or prepayment. The Company has established external trust funds to comply with the NRC's regulations. Prior to the enactment of these regulations, the Company had internally reserved nuclear decommissioning costs. 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 estimated cost of decommissioning and the amounts being recovered through rates at December 31, 1993, for the Company's ownership interest in plants
Hatch and Vogtle were as follows:
The amounts in the internal reserve are being transferred into the external trust fund over a period of approximately nine years as approved by the GPSC in its 1991 retail rate order.
The estimates approved by the GPSC for ratemaking exclude costs of non-radiated structures and site contingency costs. The actual decommissioning cost may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The Company expects the GPSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
PLANT VOGTLE PHASE-IN PLANS
In 1987 and 1989, the GPSC ordered that the costs of Plant Vogtle Units 1 and 2 be phased into rates under plans that meet the requirements of Financial Accounting Standards Board (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. II-110 NOTES (continued) Georgia Power Company 1993 Annual Report
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.
In years prior to 1993, income taxes were accounted for and reported under Accounting Principles Board Opinion No. 11. Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. See Note 7 to the financial statements for further information.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AND DEFERRED RETURN
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 1993, 1992 and 1991, the average AFUDC rates were 4.87 percent, 7.16 percent and 9.90 percent, respectively. The reduction in the average AFUDC rate since 1991 reflects the Company's greater use of lower cost short-term debt.
The Company also imputed a return on its investment in Plant Vogtle Units 1 and 2 after they began commercial operation, under short-term cost deferrals and phase-in plans as described in Note 3. AFUDC and the Vogtle deferred returns, net of taxes, as a percentage of net income after dividends on preferred stock, amounted to 1.4 percent, 2.1 percent and 9.2 percent for 1993, 1992 and 1991, 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 estimated cost of funds used during construction.
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
All financial instruments of the Company -- for which the carrying amount does not approximate fair value -- are shown in the table below at December 31:
The fair values of nuclear decommissioning trusts and investment securities were based on listed closing market prices. 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. In December 1992, the Company converted to the inventory method of accounting for certain emergency spare parts. This conversion resulted in a regulatory liability that is being amortized as credits to income over
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approximately four years. This conversion will not have a material effect on income in any year.
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 asset representing the future recoverability of this cost. This amount was $42 million at December 31, 1993, and $40 million at December 31, 1992. In 1994, approximately 72 percent of the 1993 deferred vacation costs will be expensed, and the balance will be charged to construction and other accounts.
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 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.
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. For medical care benefits, a qualified trust has been established for funding amounts to the extent deductible under federal income tax regulations. Amounts funded are primarily invested in debt and equity securities. Accrued costs of life insurance benefits, other than current cash payments for retirees, currently are not being funded.
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 -- approximately $6 million -- 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 cost on a cash basis as payments were made. The total costs of such benefits recognized by the Company in 1993, 1992, and 1991 were $56 million, $13 million, and $9 million, respectively.
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. Retiree medical and life insurance information is shown only for 1993 because Statement No. 106 was adopted as
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NOTES (continued) Georgia Power Company 1993 Annual Report
of January 1, 1993, on a prospective basis. The funded status of the plans at December 31 was as follows:
Weighted average rates used in actuarial calculations:
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 11.3 percent for 1993, 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 by 1.0 percent would increase the accumulated medical benefit obligation as of December 31, 1993, by $68 million and the aggregate of the service and interest cost components of the net retiree medical cost by $7 million.
The components of the plans' net costs are shown below:
Of net pension costs (income) recorded, $(6) million in 1993 and $5 million in 1991, were recorded to operating expense, with the balance being recorded to construction and other accounts.
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Of the above net postretirement medical and life insurance costs recorded in 1993, $21 million was charged to operating expenses, $21 million was deferred, and the remainder was charged to construction and other accounts.
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 has 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 court's decision is reversed or until the next general rate case proceeding. An association of industrial customers has filed a petition for review of such accounting order in the Superior Court of Fulton County, Georgia. The Company's costs related to these conservation programs through 1993 were $60 million of which $15 million has been collected and the remainder deferred. The estimated costs, assuming no change in the programs certified by the GPSC, are $38 million in 1994 and $40 million in 1995.
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 these financial statements.
RETAIL RATEPAYERS' SUIT CONCLUDED
In March 1993, several retail ratepayers of Georgia Power filed a civil complaint in the Superior Court of Fulton County, Georgia, against Georgia Power, The Southern Company, the system service company, and Arthur Andersen & Co. The complaint alleged that Georgia Power obtained excessive rate increases by improper accounting for spare parts and sought actual damages estimated by the plaintiffs to be in excess of $60 million -- plus treble and punitive damages -- for alleged violations of the Georgia Racketeer Influenced and Corrupt Organizations Act and other state statutes, statutory and common law fraud, and negligence. These state law allegations were substantially the same as those included in a 1989 suit brought in federal district court in Georgia. That suit and similar ones filed in Alabama, Florida, and Mississippi federal courts were subsequently dismissed.
The defendants' motions to dismiss the current complaint were granted by the Superior Court of Fulton County, Georgia, in July 1993. In January 1994, the plaintiffs' appeal of the dismissal to the Supreme Court of Georgia was rejected. This matter is now concluded.
GULF STATES SETTLEMENT
On November 7, 1991, subsidiaries of The Southern Company entered into a settlement agreement with Gulf States that resolved litigation between the companies that had been pending since 1986 and arose out of a dispute over certain unit power and long-term power sales contracts. In 1993, all remaining terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received, the Company recorded increases of $3 million in 1992 and $89 million in 1991 net income.
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 changes in the rate of return on common equity that may occur as a result of this proceeding would be effective 60 days after a proper notice of the proceeding is published. A notice was published on May 10, 1991.
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.
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NOTES (continued) Georgia Power Company 1993 Annual Report
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.
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 begun amortizing these costs (as recovered through rates) as follows:
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% 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.
4. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program and currently estimates property additions to be approximately $688 million in 1994, $555 million in 1995 and $629 million in 1996. These estimated additions include AFUDC of $19 million in 1994, $27 million in 1995, and $18 million in 1996. The estimates for property additions for the three-year period include $88 million committed to meeting the requirements of the Clean Air Act.
While the Company has no new baseload generating plants under construction, the construction of nine combustion turbine peaking units is planned to be completed by 1996. In addition, significant construction of transmission and distribution facilities, and upgrading and extending the useful life of generating plants will continue. The construction program is subject to periodic review and revision, and actual construction costs may vary from estimates because of numerous factors, including, but not limited to, changes in business conditions, load growth estimates, environmental regulations, and regulatory requirements.
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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 were approximately $4.8 billion at December 31, 1993. 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. Rental expense totaled $8 million, $7 million, and $5 million for 1993, 1992, and 1991, respectively. Minimum annual rental commitments for noncancellable rail car leases are $9 million annually for years 1994 through 1998, and total approximately $191 million thereafter.
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 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 5. The joint ownership agreement significantly reduces the risk of the project being canceled. However, full recovery of the Company's costs depends on the GPSC's treatment of the project's cost and disposition of the project's capacity output. In the event the Company cannot demonstrate to the GPSC the project's economic viability based on current ownership, construction schedule, and costs, then part or all of such costs may have to be written off in accordance with FASB Statement No. 90, Accounting for Abandonments and Disallowed Plant Costs. At December 31, 1993, the Company's investment in the project amounted to approximately $197 million. 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 portion of the estimated total plant additions at completion would be approximately $199 million. The plant is currently scheduled to begin commercial operation in 1995.
The Company has held preliminary discussions with other parties regarding the potential disposition of its remaining interest in the project.
The ultimate outcome of this matter cannot now be determined.
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 limits to $9.4 billion 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 $171 million per incident but not more than an aggregate of $22 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 adjustment in the event that losses exceed accumulated reserve funds. The Company's maximum assessment per incident is limited to $18 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
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Insurance Limited (NEIL), a mutual insurance company, and American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters.
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 $2.3 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 assessments per incident under the current policies for the Company would be $15 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 $7 million.
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; the Municipal Electric Authority of Georgia (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 two 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 $806 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:
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 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% of the project (194 megawatts of capacity) at completion.
The Company will own six of eight 80 megawatt combustion turbine generating units and 75% of the related common facilities being jointly constructed with Savannah Electric, an affiliate. The Company's investment in the project at December 31, 1993, was $100 million and is expected to total approximately $182 million when the project is completed. All units are
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expected to be completed by June, 1995. Savannah Electric will operate these units.
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 $183 million, $289 million and $320 million in 1993, 1992 and 1991, respectively. The Plant Scherer buyback agreements ended in 1993. The current projected Plant Vogtle capacity payments for the next five years are as follows: $132 million in 1994, $77 million in 1995, $70 million in 1996, $59 million in 1997 and $59 million in 1998. 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, 1993, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation, were as follows:
(1) Investment net of write-offs.
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 expiring in 1994, 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. An amended contract has been filed with the FERC with substantially the same provisions, but the term thereof would be extended automatically for two year periods, subject to any 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
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Income, is as follows:
At December 31, 1993, the capitalization of SEGCO consisted of $58 million of equity and $84 million of long-term debt on which the annual interest requirement is $3.8 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 certain non-affiliated utilities located outside the system's service territory. Certain of these agreements are non-firm and are based on the capacity of the Southern system. Other agreements are firm and pertain to capacity related to specific generating units. Because energy is generally sold at cost under these agreements, it is primarily the capacity revenues that affect the Company's profitability. The capacity revenues have been as follows:
Long-term non-firm power of 400 megawatts was sold by the Southern electric system in 1993 to Florida Power Corporation (FPC). This amount decreases to 200 megawatts in 1994 and the contract expires 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 830 megawatts of capacity in 1993 and is scheduled to sell approximately 403 megawatts of capacity in 1994. Thereafter, these sales will decline to an estimated 157 megawatts by the end of 1996 and will remain at that approximate level through 1999. After 2000, capacity sales will decline to approximately 101 megawatts -- unless reduced by FPL and JEA -- until the expiration of the contracts in 2010.
7. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption of Statement No. 109 resulted in cumulative adjustments that had no material effect on net income. The adoption also resulted in the recording of additional deferred income taxes and related assets and liabilities. The related assets of $993 million are revenues to be received from customers. These assets are attributable to tax benefits flowed-through to customers in prior years, and taxes applicable to capitalized AFUDC. The related liabilities of $453 million are revenues to be refunded to customers. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Additionally, deferred income taxes related to accelerated tax depreciation previously shown as a reduction to utility plant were reclassified.
Details of the federal and state income tax provisions are as follows:
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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 basis, which give rise to deferred tax assets and liabilities are as follows:
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 $19 million in 1993, $19 million in 1992, and $27 million in 1991. At December 31, 1993, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to effective income tax rate is as follows:
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, 1993, $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, 1993, the ratio as defined was 46.1 percent.
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REMARKETED BONDS
In 1992, the Company issued two series of variable rate first mortgage bonds each with principal amounts of $100 million due 2032. The current composite interest rate on the bonds is 6.20 percent and is fixed for the first three years of the issues.
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 $407.7 million 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 $1.3 billion 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:
BANK CREDIT ARRANGEMENTS
At the beginning of 1994, the Company had unused credit arrangements with banks totaling $540 million, of which $10 million expires June 30, 1994, $130 million expires at May 1, 1996, and $400 million expires at June 30, 1996.
The $400 million expiring June 30, 1996, 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 1996, short-term borrowings may be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at the companies' option. In addition, these agreements require payment of commitment fees based on the unused portions of the commitments or the maintenance of compensating balances with the banks.
The $10 million credit arrangement expiring in 1994 allows borrowings for up to 90 days. Commitment fees are based on the unused portion of the commitment.
In addition, the Company borrows under uncommitted lines of credit with banks and through a $150 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 1993.
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, 1993, the Company had a capitalized lease obligation for its corporate headquarters building of $88 million with an interest rate of 8.1 percent. Other capitalized lease obligations were $137 thousand with a composite interest rate of 6.8 percent.
The maturities of capital lease obligations through 1998 are approximately as follows: $423 thousand in 1994, $309 thousand in 1995, $335 thousand in 1996, $362 thousand in 1997, and $392 thousand in 1998.
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
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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, 1993, and 1992, the interest and lease amortization deferred on the Balance Sheets are $47 million and $48 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:
*Less than .1 million
The indenture's first mortgage bond improvement fund requirement amounts to 1 percent of each outstanding series of bonds authenticated under the indenture prior to January 1 of each year, other than those issued to collateralize pollution control obligations. The requirement may be satisfied by depositing cash or reacquired bonds, or by pledging additional property equal to 1 2/3 times the requirement. The 1993 and 1992 requirements were met in the first quarter of each year by depositing cash subsequently used to redeem bonds. The 1994 requirement was funded in December 1993.
REDEMPTION OF HIGH-COST SECURITIES
The Company plans to continue a program of redeeming or replacing high-cost debt and preferred stock in cases where opportunities exist to reduce financing costs. High-cost 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 by 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 1993 and 1992 is as follows:
The Company's business is influenced by seasonal weather conditions and the timing of rate increases.
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SELECTED FINANCIAL AND OPERATING DATA Georgia Power Company 1993 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Georgia Power Company 1993 Annual Report
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand * Less than one-tenth of one percent.
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SELECTED FINANCIAL AND OPERATING DATA (continued) Georgia Power Company 1993 Annual Report
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STATEMENTS OF INCOME Georgia Power Company
Note: Reflects major sales of facilities to Jacksonville Electric Authority, Florida Power & Light Company, OPC, MEAG, and Dalton. Increases in net income, after total taxes, from these sales were $18,391,000 in 1993, $14,542,000 in 1991, $6,336,000 in 1990, $3,851,000 in 1987, and $21,250,000 in 1984.
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STATEMENTS OF INCOME Georgia Power Company
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STATEMENTS OF CASH FLOWS Georgia Power Company
( ) Denotes use of cash.
II-129 STATEMENTS OF CASH FLOWS Georgia Power Company
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BALANCE SHEETS Georgia Power Company
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BALANCE SHEETS Georgia Power Company
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BALANCE SHEETS Georgia Power Company
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GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
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GEORGIA POWER COMPANY
OUTSTANDING SECURITIES (Continued) AT DECEMBER 31, 1993
(1) Issued in exchange for $5.00 preferred outstanding at the time of company formation.
II-136
GEORGIA POWER COMPANY
SECURITIES RETIRED DURING 1993
FIRST MORTGAGE BONDS
(1) Issued in exchange for $5.00 preferred outstanding at the time of company formation. * Less than $500.
II-137
GULF POWER COMPANY
FINANCIAL SECTION
II-138
MANAGEMENT'S REPORT Gulf Power Company 1993 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 the 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/ D. L. McCrary /s/ A. E. Scarbrough - -------------------------- ------------------------ Douglas L. McCrary Arlan E. Scarbrough Chairman of the Board Vice President - Finance and Chief Executive Officer
II-139 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, 1993 and 1992, 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, 1993. 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-148 through II-165) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 1993 and 1992, 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 & Co.
Atlanta, Georgia February 16, 1994
II-140 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
Gulf Power Company's net income after preferred stock dividends was $54.3 million for 1993, a $0.2 million increase over 1992 net income. Earnings reflect a $2.3 million gain on the sale of Gulf States Utilities Company (Gulf States) stock and the reversal of a $1.7 million wholesale rate refund as the result of a court order which is further discussed in Note 3 to the financial statements under "Recovery of Contract Buyout Costs". 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, offset by higher operation and maintenance expense, and decreased industrial sales reflecting the loss of the Company's largest industrial customer, Monsanto, which began cogeneration in August of 1993.
The Company's 1992 net income after dividends on preferred stock decreased $3.7 million compared to the prior year. The 1991 earnings included an after-tax gain of $12.7 million representing the settlement of litigation with Gulf States. See Note 7 to the financial statements under "Gulf States Settlement Completed" for further details. Excluding this settlement from 1991, earnings for 1992 increased $8.4 million -- or approximately -- 18.7 percent over 1991. This improvement was due to increased energy sales; lower interest expense and preferred dividends as a result of security refinancings; and continued emphasis on cost controls.
The Company's return on average common equity was 13.29 percent for 1993, a slight decrease from the 13.62 percent return earned in 1992, which was up from the 12.03 percent earned in 1991 (excluding the Gulf States settlement).
REVENUES
Changes in operating revenues over the last three years are the result of the following factors:
* Includes the non-interest portion of the wholesale rate refund reversal discussed in "Earnings."
Retail revenues of $471.7 million in 1993 increased $10.2 million or 2.2 percent from last year, compared with an increase of 1.2 percent in 1992 and 4.9 percent in 1991. Revenues increased in the residential and commercial classes primarily due to customer growth, and favorable weather and economic conditions. Revenues in the industrial class declined due to the loss of the Company's largest industrial customer, Monsanto, which began operating its cogeneration facility in August 1993. See "Future Earnings Potential" for further details. The change in base rates for 1993 and 1992 reflects the expiration of a retail rate penalty in September 1992.
Sales for resale were $95.4 million in 1993, increasing $1.2 million or 1.3 percent over 1992. Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. 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
II-141 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1993 Annual Report
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:
Beginning in June 1992, all the capacity from the Company's ownership portion of Plant Scherer Unit No. 3 was sold through unit power sales, resulting in increased capacity revenues.
In 1993, changes in other operating revenues are primarily due to the recognition of $2.6 million under the Environmental Cost Recovery (ECR) clause which is fully discussed in Note 3 to the financial statements under "Environmental Cost Recovery", which is offset by true-ups of other regulatory cost recovery clauses. The increase in other operating revenues in 1992 was primarily due to true-ups of regulatory cost recovery clauses and the changes in franchise fee collections and Florida gross receipts taxes (discussed under "Expenses") which had no effect on earnings.
Energy sales for 1993 and percent changes in sales since 1991 are reported below.
Overall retail sales remained relatively flat in 1993. Increases in residential and commercial sales -- reflecting customer growth, favorable weather and an improving economy -- were offset by the decreased sales in the industrial class reflecting the loss of Monsanto. Retail sales increased 3.8 percent in 1992 primarily due to an increase in the number of customers served and a moderately improving economy.
Energy sales for resale to non-affiliates increased 2.0 percent and are predominantly 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 above.
EXPENSES
Total operating expenses for 1993 increased $16.6 million or 3.5 percent over 1992 primarily due to increased operation and maintenance expenses and higher taxes. Other operation expenses increased $10.9 million or 11.1 percent from the 1992 level. The increase is attributable to additional costs of $7.4 million related to increases in the buyout of coal supply contracts and $1.4 million of environmental clean-up costs. Also, higher employee benefit costs and the costs of an automotive fleet reduction program increased expenses by $2.1 million. Operating expenses for 1992 increased by approximately $16 million over 1991. Excluding the Gulf States settlement, an after-tax reduction of $0.6 million in 1992 and $12.7 million in 1991, 1992 total operating expenses increased $4.3 million or 0.9 percent over 1991.
Fuel and purchased power expenses decreased $3.8 million or 1.8 percent from 1992 reflecting the lower cost of fuel. Total 1992 fuel and purchased power increased $1.4 million or 0.7 percent from 1991.
Maintenance expense increased $4.1 million or 9.7 percent over 1992 due to scheduled maintenance of production facilities. The 1992 maintenance expense was down $3.5 million or 7.7 percent from 1991 due to a decrease in scheduled maintenance.
Federal income taxes increased $0.7 million primarily due to a corporate federal income tax rate increase from 34 percent to 35 percent effective January 1993. Taxes other than income taxes increased $2.3 million in 1993, an increase of 6.1 percent over the 1992 expense
II-142 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1993 Annual Report
primarily due to increases in property taxes and gross receipt taxes. Taxes other than income taxes decreased $4.5 million, or 10.5 percent in 1992 compared to 1991 due primarily to the Company discontinuing the collection of franchise fees for two Florida counties which was partially offset by an increase in gross receipt taxes. Changes in franchise fee collections and gross receipt taxes had no impact on earnings.
Interest expense decreased $3.2 million or 8.1 percent from the 1992 level and 1992 interest expense decreased $5.6 million or 12.5 percent from 1991. The decrease in both years is primarily attributable to refinancing some of the Company's higher cost securities.
EFFECTS OF INFLATION
The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its cost of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in long-lived utility plant. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
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. It is expected that higher operating costs and carrying charges on increased investment in plant, if not offset by proportionate increases in operating revenues (either by periodic rate increases or increases in sales), will adversely affect future earnings. Growth in energy sales will be subject to a number of factors, including the volume of sales to neighboring utilities, energy conservation practiced by customers, the elasticity of demand, customer growth, weather, competition, and the rate of economic growth in the service area.
In addition to the traditional factors discussed above, the Energy Policy Act of 1992 (Energy Act) will have a profound 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 preparing to meet the challenges of a major change in the traditional business practices 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, and this may enhance the incentive for IPPs to build cogeneration plants for the Company's large industrial and commercial customers and sell excess energy generation to the Company or other utilities. Although the Energy Act does not require transmission access to retail customers, pressure for legislation to allow retail wheeling will continue. If the Company does not remain a low-cost producer and provide quality service, the Company's retail energy sales growth, its ability to retain large industrial and commercial customers, and obtain new long-term contracts for energy sales outside the Company's service area, could be limited, and this could significantly erode earnings.
The future effect of cogeneration and small-power production facilities cannot be fully determined at this time, but may be adverse. One effect of cogeneration which the Company has experienced is the loss of its largest industrial customer, Monsanto, in August of 1993. The loss of the Monsanto load reduced revenues, and will result in a reduction in net income of approximately $3 million in the first twelve months.
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".
II-143 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1993 Annual Report
Also, recently enacted legislation that provides for recovery of prudent environmental compliance costs is discussed in Note 3 to the financial statements under "Environmental Cost Recovery."
The Company filed a notice with the Florida Public Service Commission (FPSC) of its intent to obtain rate relief in February 1993. On May 4, 1993, the FPSC approved a stipulation between the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group to cancel the filing of the rate case. The stipulation also allowed the Company to retain, for the next four years, its existing method for calculating accruals for future power plant dismantlement costs. The existing method provides a more even allocation of expenses over the life of the plants and results in an avoided increase in expenses of about $6 million annually over the next four years when compared to the FPSC method. The stipulation also provided for the reduction of the Company's allowed return on equity midpoint from 12.55 percent to 12.0 percent. After the February 1993 filing date, interest rates continued to remain low, resulting in lower cost of capital. Also, the Florida legislature adopted legislation which allows utilities to petition the FPSC for recovery of environmental costs through an adjustment clause if these costs are not being recovered in base rates. See Note 3 to the financial statements under "Environmental Cost Recovery" for further details. The combination of the circumstances discussed above, placed the Company in a better position to manage its finances without an increase in base rates while still providing a fair return for the Company's investors. Consequently, the Company agreed, as a part of this stipulation, to cancel the filing of the rate case.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112, Employers' Accounting for Postemployment Benefits, which must be effective by 1994. The new standard requires that all types of benefits provided to former or inactive employees and their families prior to retirement be accounted for on an accrual basis. These benefits include salary continuation, severance pay, supplemental benefits, disability-related benefits, job training, and health and life insurance coverage. In 1993, the Company adopted Statement No. 112, which resulted in a decrease in earnings of $0.3 million.
The FASB has issued Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which is effective in 1994. Statement No. 115 supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities. The Company does not have any investments that qualify for FASB Statement No. 115 treatment.
FINANCIAL CONDITION
OVERVIEW
The principal changes in the Company's financial condition during 1993 were gross property additions of $79 million. Funds for these 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.
On January 1, 1993, the Company changed its method of calculating the accruals for postretirement benefits other than pensions and its method of accounting for income taxes. See Notes 2 and 8 to the financial statements, regarding the impact of these changes.
FINANCING ACTIVITIES
As mentioned above, the Company continued to lower its financing costs by issuing new securities and other debt, and retiring higher-cost issues in 1993. The Company sold $75 million of first mortgage bonds and, through public authorities, $53.4 million of pollution control revenue bonds, issued $35 million of preferred stock, and obtained $25 million with a long-term bank note. Retirements, including maturities during 1993, totaled $88.8 million of first mortgage bonds, $40.7 million of pollution control revenue bonds, and $21.1 million of preferred stock. (See the Statements of Cash Flows for further details.)
II-144 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1993 Annual Report
Composite financing rates for the years 1991 through 1993 as of year end were as follows:
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $200 million for the three years beginning 1994 ($77 million in 1994, $55 million in 1995, and $68 million in 1996). The estimates of property additions for the three-year period include $25 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, the Company plans to construct two 80 megawatt combustion turbine peaking units. The first is scheduled to be completed in 1998, and the second in 1999. 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 $86 million will be required by the end of 1996 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.
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 must be implemented 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.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate 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 allocating 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 market for emission allowances is developing slower than expected. However, The Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, and this has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment would be installed on all fossil-fired units. Under this Phase I compliance approach, additional construction expenditures are estimated to total approximately $275 million for The Southern Company including $34 million for Gulf Power Company through 1995.
II-145 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1993 Annual Report
Phase II compliance costs are expected to be higher because requirements are stricter and all fossil-fired generating plants are affected. For 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 construction expenditures ranging from approximately $450 million to $800 million for The Southern Company including approximately $30 million to $40 million for Gulf Power Company. However, the full impact of Phase II compliance cannot now be determined with certainty, pending the 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 Commission 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 Gulf Power Company customers could be necessary to fully recover the cost of compliance for both Phase I and Phase 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.
The Florida Legislature recently adopted legislation that allows a utility to petition the FPSC for recovery of prudent environmental compliance costs through an ECR clause without lengthy regulatory full revenue requirements rate proceedings. The legislation is discussed in Note 3 to the financial statements under "Environmental Cost Recovery".
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The study will serve as the basis for 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 is expected to take some action on this issue in 1994. 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 1994 or 1995, the EPA is expected to 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.
Gulf Power 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.
II-146 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 1993 Annual Report
Several major pieces of environmental legislation are in the process of being reauthorized or amended by Congress. These include: the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; and the Resource Conservation and Recovery Act. Changes to these laws could affect many areas of Gulf Power 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 Gulf Power 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.
COAL STOCKPILE DECREASES
To reduce the working capital invested in the coal stockpile inventory, the Company implemented a coal stockpile reduction program in 1992. The Company's actual year end inventory at December 31, 1993 was $20.7 million which is considerably lower than the desired level of $31.4 million. This situation exists because a limited supply of coal was available at competitive prices primarily due to the United Mine Workers strike from July to December 1993. In addition, barge transportation was stranded due to floods in the Midwest. As a result of these circumstances, management chose to allow the existing coal inventory to decline until coal prices stabilized. Current market conditions indicate that substantial coal supplies at competitive prices are now available. Therefore, the Company plans to increase purchases and return the coal stockpile inventory to the desired level by the end of the third quarter, 1994.
SOURCES OF CAPITAL
At December 31, 1993, the Company had $5.6 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; 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.
II-147 STATEMENTS OF INCOME For the Years Ended December 31, 1993, 1992, and 1991 Gulf Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-148 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993, 1992, and 1991 Gulf Power Company 1993 Annual Report
( ) Denotes use of cash. The accompanying notes are an integral part of these statements.
II-149 BALANCE SHEETS At December 31, 1993 and 1992 Gulf Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-150 BALANCE SHEETS (continued) At December 31, 1993 and 1992 Gulf Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-151 STATEMENTS OF CAPITALIZATION At December 31, 1993 and 1992 Gulf Power Company 1993 Annual Report
II-152 STATEMENTS OF CAPITALIZATION (CONTINUED) At December 31, 1993 and 1992 Gulf Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-153 STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993, 1992, and 1991 Gulf Power Company 1993 Annual Report
STATEMENTS OF PAID-IN CAPITAL For the Years Ended December 31, 1993, 1992, and 1991 Gulf Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-154 NOTES TO FINANCIAL STATEMENTS At December 31, 1993, 1992 and 1991 Gulf Power Company 1993 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, Southern Company Services, Inc. (SCS), Southern Electric International (Southern Electric), Southern Nuclear Operating Company (Southern Nuclear) and various other subsidiaries related to foreign utility operations and domestic non-utility operations. At this time, the operations of the other subsidiaries are not material. 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 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.
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 these commissions.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
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 fuel is used. The Company's electric rates include provisions to periodically adjust billings for fluctuations in fuel and the energy component of purchased power costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates. The FPSC has also approved the recovery of purchased power capacity costs, energy conservation costs, and environmental compliance costs in cost recovery clauses that are similar to the method used to recover fuel costs.
DEPRECIATION AND AMORTIZATION
Depreciation of the original cost of depreciable utility plant in service is provided primarily using composite straight-line rates which approximated 3.8 percent in 1993, 1992, and 1991. 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.
In years prior to 1993, income taxes were accounted for and reported under Accounting Principles Board Opinion No. 11. 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.
II-155 NOTES (CONTINUED) Gulf Power Company 1993 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 certain new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of plant through a higher rate base and higher depreciation expense. The FPSC-approved composite rate used to calculate AFUDC was 7.27 percent effective on July 1, 1993 and 8.03 percent for the first half of 1993, and for 1992, and 1991. AFUDC amounts for 1993, 1992, and 1991 were $966 thousand, $60 thousand, and $149 thousand, respectively. The increase in 1993 is 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.
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 -- are shown in the table below as of December 31:
The fair values of investment securities were based on listed closing market prices. 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 $4.0 million and $3.8 million at December 31, 1993 and 1992, respectively. In 1994, an estimated 84 percent of the 1993 deferred vacation cost
II-156 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
will be expensed and the balance will be charged to construction.
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 is providing 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 $2.2 million and $2.5 million at December 31, 1993 and 1992, 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, 1993 and 1992, the accumulated provision for property damage amounted to $10.5 million and $9.7 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.
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 has been established for funding amounts to the extent deductible under federal income tax regulations. Amounts funded are primarily invested in debt and equity securities. Accrued costs of life insurance benefits, other than current cash payments for retirees, currently are not being funded.
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." Prior to the adoption of Statement No. 106, Gulf Power 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 costs of such benefits recognized by the Company in 1993, 1992, and 1991 were $3.9 million, $3.1 million, and $2.7 million, respectively.
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. Retiree medical and life insurance information is shown only for 1993 because Statement No. 106 was adopted as of January 1, 1993, on a prospective basis.
II-157 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
The funded status of the plans at December 31 was as follows:
The weighted average rates assumed in the actuarial calculations were:
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 11.3 percent for 1993, 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 by 1.0 percent would increase the accumulated medical benefit obligation as of December 31, 1993, by $4.8 million and the aggregate of the service and interest cost components of the net retiree medical cost by $543 thousand.
Components of the plans' net cost are shown below:
Of the above net pension amounts, $(601) thousand in 1993, $3 thousand in 1992, and $518 thousand in 1991, were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Of the above net postretirement medical and life insurance amounts recorded in 1993, $3.0 million was recorded in operating expenses, and the remainder was recorded in construction and other accounts.
II-158 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
3. LITIGATION AND REGULATORY MATTERS:
COAL BARGE TRANSPORTATION SUIT
On August 19, 1993, a complaint against the Company and Southern Company Services, an affiliate, was filed in federal district court in Ohio by two companies with which the Company had contracted for the transportation by barge for certain of the Company's coal supplies. The complaint alleges breach of the contract by the Company and seeks damages estimated by the plaintiffs to be in excess of $85 million.
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.
FPSC APPROVES STIPULATION
In February 1993, the Company filed a notice with the FPSC of its intent to obtain rate relief. On May 4, 1993, the FPSC approved a stipulation between the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group to cancel the filing of the rate case and to allow the Company to retain for the next four years its existing method for calculating accruals for future power plant dismantlement costs. The stipulation also required the reduction of the Company's allowed return on equity midpoint from 12.55 percent to 12.0 percent. See Management's Discussion and Analysis under "Future Earnings Potential" for further details of circumstances that contributed to the company canceling the rate case.
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 occur as a result of this proceeding would be effective 60 days after a proper notice of the proceeding is published. A notice was published on May 10, 1991.
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.
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.
RECOVERY OF CONTRACT BUYOUT COSTS
In July 1990, the Company filed a request for waiver of FERC's fuel adjustment charge regulation to permit recovery of coal contract buyout costs from wholesale customers. On April 4, 1991, the FERC issued an order granting recovery of the buyout costs from wholesale customers from July 19, 1990, forward, but denying retroactive recovery of the buyout costs from January 1, 1987 through July 18, 1990. The Company's request for rehearing was denied by the FERC. The Company refunded $2.7 million (including interest) in June 1991 to its wholesale customers. On July 31, 1991, the Company filed a petition for review of the FERC's decision to the U.S. Court of Appeals for the District of Columbia Circuit. On January 22, 1993, the Court vacated the Commission's order, finding FERC's denial of the Company's request for a retroactive waiver to be arbitrary and capricious. The Court remanded the matter to FERC for consideration consistent with its opinion. Management expects that the commission will ultimately allow the Company to recover the amount refunded plus interest. Accordingly, the Company recorded the reversal of the $2.7 million refund to income in 1993.
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.
II-159 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
On January 12, 1994, the FPSC approved the Company's petition under the ECR clause for recovery of environmental costs that were projected to be incurred from July 1993 through September 1994. The order allows the recovery from customers of such costs amounting to $7.8 million during the period, February through September 1994. Thereafter, recovery under ECR will be determined semi-annually and will include a true-up of the prior period and a projection of the ensuing six-month period. In December 1993, the Company recorded $2.6 million as additional revenue for the portion of costs incurred during 1993.
4. CONSTRUCTION PROGRAM:
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $77 million in 1994, $55 million in 1995, and $68 million in 1996. These estimates include AFUDC of approximately $0.7 million, $0.3 million, and $0.2 million, in 1994, 1995, and 1996, respectively. 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 baseload generating plants under construction. However, the Company plans to construct two 80 megawatt combustion turbine peaking units. The first is scheduled to be completed in 1998, and the second in 1999. 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.
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, preferred stock, 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. Because of the attractiveness of current short term interest rates, the Company may maintain a higher level of short term indebtedness than has historically been true.
At December 31, 1993, the Company had $49 million of lines of credit with banks of which $6.1 million was committed to cover checks presented for payment. These credit arrangements are subject to renewal June 1 of each year. In connection with these committed lines of credit, 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. In addition, the Company has bid-loan facilities with eight major money center banks that total $180 million, of which, none was committed at December 31, 1993.
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 $1.4 billion at December 31, 1993. 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
II-160 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
this payment was some $60 million. This amount is being amortized to expense on a per ton basis over a nine-year period. The remaining unamortized amount included in deferred charges, including the current portion, was $18 million at December 31, 1993.
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 included in deferred charges, including the current portion, was $36 million at December 31, 1993.
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 is being amortized to expense on a per ton basis over a one year period. The remaining unamortized amount, which is included in current assets, was $11 million at December 31, 1993.
The amortization of these payments is being recovered through the fuel cost recovery clause discussed under "Revenues and Fuel Costs" in Note 1.
LEASE AGREEMENT
In 1989, the Company entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars to transport coal to Plant Daniel. Mississippi Power, as joint owner of Plant Daniel, is responsible for one half of the lease costs. The Company's share of the lease is charged to fuel inventory and allocated to fuel expense as the fuel is used. The lease costs charged to inventory were $1.2 million in 1993, $1.2 million in 1992 and $1.3 million in 1991. For the year 1994, the Company's annual lease payment will be $1.2 million. The Company's annual lease payment for 1995 will be $2.4 million and for 1996, 1997, and 1998 the payment will be $1.2 million. Lease payments after 1998 total approximately $17.4 million. The Company has the option, after three years from the date of the original contract, to purchase the railcars at the greater of termination value or fair market value. Additionally, at the end of the 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, 1993, the Company's percentage ownership and its amount of investment in these jointly owned facilities were as follows:
(1) Includes net plant acquisition adjustment. (2) Total megawatt nameplate capacity: Plant Scherer Unit No. 3: 818 Plant Daniel: 1,000
II-161 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS:
GENERAL
The Company and the other operating affiliates of The Southern Company have contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside of the system's service area. Certain of these agreements are non-firm and are based on the capacity of the system in general. Other agreements are firm and pertain to capacity related to specific generating units. Because the energy is generally sold at cost under these agreements, the capacity revenues from these sales primarily affect profitability. The Company's capacity revenues have been as follows:
Long-term non-firm power of 400 megawatts was sold in 1993 to Florida Power Corporation (FPC) by the Southern electric system. In 1994, this amount decreased to 200 megawatts, and the contract will expire at year-end 1994. Capacity and energy sales under these long-term non-firm power sales agreements are made from available power pool capacity, and the revenues from the sales are 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, 209 megawatts of net dependable capacity were sold by the Company during 1993, and sales will remain at that approximate 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 $39.5 million in 1993, $46.2 million in 1992, and $42.1 million in 1991, or 6.8 percent, 8.1 percent, and 7.5 percent of operating revenues, respectively.
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, the subsidiaries of The Southern Company entered into a settlement agreement with Gulf States Utilities Company (Gulf States) that resolved litigation between the companies that had been pending since 1986 and arose out of a dispute over certain unit power and other long-term power sales contracts. In 1993, all remaining terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received - less the amounts previously included in income - the Company recorded increases in net income of approximately $0.6 million in 1992 and $12.7 million in 1991. In 1993, the Company sold all of its remaining Gulf States common stock received in the settlement, resulting in a gain of $2.3 million after tax.
8. INCOME TAXES:
Effective January 1, 1993, Gulf Power Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption of Statement No. 109 resulted in cumulative adjustments that had no effect on net income. The adoption also resulted in the recording of additional deferred income taxes and related assets and liabilities. The related assets of $31.3 million are revenues to be received from customers. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. The related liabilities of $76.9 million are revenues to be refunded to customers. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Additionally, deferred income taxes related to accelerated tax depreciation previously shown as a reduction to utility plant were reclassified.
II-162 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
Details of the federal and state income tax provisions are as follows:
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:
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 1993, 1992 and 1991. At December 31, 1993, 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:
Gulf Power 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.
II-163 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
9. LONG-TERM DEBT:
POLLUTION CONTROL OBLIGATIONS
Obligations incurred in connection with the sale by public authorities of tax-exempt pollution control revenue bonds are as follows:
* Sinking fund requirement applicable to the 6 percent pollution control bonds is $100 thousand for 1994 with increasing increments thereafter through 2005, with the remaining balance due in 2006.
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.
OTHER LONG-TERM DEBT
Long-term debt also includes $17.5 million for the Company's portion of notes payable issued in connection with the termination of Plant Daniel coal contracts (see Note 5 for information on fuel commitments). The notes bear interest at 8.25 percent with the principal being amortized through 1995. Also included in long-term debt is a 30-month note payable for $25 million which was obtained to refinance higher cost securities. The principal is due in June 1996 and bears interest at 4.69 percent which is payable quarterly beginning March 1994. The estimated annual maturities of the notes payable through 1996 are as follows: $8.4 million in 1994, $9.1 million in 1995, and $25 million in 1996.
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:
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. In 1994, $12 million of 4 5/8 percent First Mortgage Bonds due October 1, 1994 and $15 million of 6 percent First Mortgage Bonds due June 1, 1996 are scheduled to be redeemed.
II-164 NOTES (CONTINUED) Gulf Power Company 1993 Annual Report
11. COMMON STOCK DIVIDEND RESTRICTIONS:
The Company's first mortgage bond indenture contains various common stock dividend restrictions which remain in effect as long as the bonds are outstanding. At December 31, 1993, $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 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, 1993, the ratio was 44.4 percent.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial data for 1993 and 1992 are as follows:
The Company's business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.
II-165 SELECTED FINANCIAL AND OPERATING DATA Gulf Power Company 1993 Annual Report
II-166 SELECTED FINANCIAL AND OPERATING DATA (CONTINUED) Gulf Power Company 1993 Annual Report
II-167 SELECTED FINANCIAL AND OPERATING DATA (CONTINUED) Gulf Power Company 1993 Annual Report
II-168 SELECTED FINANCIAL AND OPERATING DATA (CONTINUED) Gulf Power Company 1993 Annual Report
II-169
STATEMENTS OF INCOME Gulf Power Company
II-170
STATEMENTS OF INCOME Gulf Power Company
II-171
STATEMENTS OF CASH FLOWS Gulf Power Company
II-172
STATEMENTS OF CASH FLOWS Gulf Power Company
II-173
BALANCE SHEETS Gulf Power Company
II-174
BALANCE SHEETS Gulf Power Company
II-175 BALANCE SHEETS Gulf Power Company
II-176
BALANCE SHEETS Gulf Power Company
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GULF POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
POLLUTION CONTROL BONDS
PREFERRED STOCK
(1) Subject to mandatory redemption of 5% annually on or before February 1.
II-178
GULF POWER COMPANY
SECURITIES RETIRED DURING 1993
FIRST MORTGAGE BONDS
POLLUTION CONTROL BONDS
PREFERRED STOCK
II-179
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-180
MANAGEMENT'S REPORT Mississippi Power Company 1993 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, however, in any system of internal control, 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/ Thomas A. Fanning -------------------------------------------------- Thomas A. Fanning Vice President and Chief Financial Officer
II-181
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, 1993 and 1992, 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, 1993. 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-190 through II-206) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 1993 and 1992, 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 9 to the financial statements, effective January 1, 1993, Mississippi Power Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen & Co.
Atlanta, Georgia February 16 , 1994
II-182
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
Mississippi Power Company's net income after dividends on preferred stock for 1993 totaled $42.4 million, an increase of $5.6 million over the prior year. This improvement is attributable primarily to increased energy sales and retail rate increases. A retail rate increase under the Company's Performance Evaluation Plan (PEP-1A) of $6.4 million annually became effective in July 1993. Under the Environmental Compliance Overview Plan (ECO Plan) retail rates increased by $2.6 million annually effective April 1993.
A comparison of 1992 to 1991 - excluding the events occurring in 1991 discussed below - would reflect a 1992 increase in earnings of $4.9 million or 15.5 percent. The Company's financial performance in 1991 reflected the after-tax operating and disposal losses of $11.9 million recorded by the Company's former merchandise subsidiary. These losses were partially offset by a $2.6 million positive impact on earnings from the settlement of the contract dispute with Gulf States Utilities Company (Gulf States).
REVENUES
The following table summarizes the factors impacting operating revenues for the past three years:
*Includes the effect of the retail rate increase approved under the ECO Plan.
Retail revenues of $368 million in 1993 increased 9.0 percent over the prior year, compared with an increase of 2.2 percent for 1992 and a decrease of 1.5 percent in 1991. The increase in retail revenues for 1993 was a result of growth in energy sales and customers, the favorable impact of weather, and retail rate increases. Changes in base rates reflect rate changes made under the PEP plans and the ECO Plan as approved by the Mississippi Public Service Commission (MPSC).
The increase in revenues for the recovery of fuel costs for 1993 reversed two years of decline. 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 1993 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 in 1993 increased 9.0 percent over the prior year with the related revenues rising 14.1 percent. 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. The capacity and energy components were:
Capacity revenues for Mississippi Power increased in 1993 and 1992 due to a change 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.
The increase in other operating revenues for 1993 was due to increased rents collected from microwave equipment use and the transmission of non-associated companies' electricity.
Below is a breakdown of kilowatt-hour sales for 1993 and the percent change for the last three years:
Total retail energy sales in 1993 increased compared to the previous year, due primarily to weather influences and the improvement in the economy. The increase in commercial energy sales also reflects the impact of recently established casinos within the Company's service area. Industrial sales increased in 1992 as a result of new contracts with two large industrial customers.
The decrease in energy sales for resale to non-affiliates is predominantly due to reductions in unit power sales under long-term contracts to Florida utilities. Economy sales and amounts sold under short-term contracts are also sold for resale to non-affiliates. 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 1993 were higher than the previous year because of higher production expenses, which reflects increased demand, an increase in the federal income tax rate, and higher employee-related costs. (See Note 2 to the financial statements for information regarding employee and retiree benefits.) Additionally, included in other operation expenses are increased costs associated with environmental remediation of a Southern electric system research facility. Expenses in 1992 were lower than 1991, excluding the Gulf States settlement, primarily because of lower production expenses stemming from decreased demand.
II-184 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1993 Annual Report
Fuel costs constitute the single largest expense for Mississippi Power. These costs increased in 1993 due to an 11.0 percent increase in generation, which reflects higher demand. Fuel expenses in 1992, compared to 1991, were lower because of less generation and the negotiation of new coal contracts. Generation decreased primarily because of the availability of lower cost generation elsewhere within the Southern electric system.
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.
Taxes other than income taxes increased in 1993 because of higher ad valorem taxes, which are property based, and municipal franchise taxes, which are revenue based. The decline in 1992 was attributable to lower franchise taxes.
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. The change in income taxes for 1992 and 1991 reflected the change in operating income.
EFFECTS OF INFLATION
Mississippi Power is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in long-lived utility plant. Conventional accounting for historical costs does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors ranging from regulatory matters to growth in energy sales. 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 curbing the construction budget. Operating revenues will be affected by any changes in rates under the PEP-2, the Company's revised performance based ratemaking plan. The PEP plans have proved 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 regulations. The ECO Plan is operated independently of PEP-2.
The 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. Also, pending before the FERC is the Company's request for a $3.6 million wholesale rate increase.
Further discussion of the PEP plans, the ECO Plan, and proceedings before the FERC is made in Note 3 to the financial statements herein.
Future earnings in the near term will depend upon growth in energy sales, which are subject to a number of factors. Traditionally, these factors have included 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1993 Annual Report
Policy Act of 1992 (Energy Act) will have a profound 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 Energy Act allows Independent Power Producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities, and this may enhance the incentive of IPPs to build cogeneration plants for a utility's large industrial and commercial customers. Although the Energy Act does not require transmission access to retail customers, pressure for legislation to allow retail wheeling will continue. Mississippi Power is preparing to meet the challenge of this major change in the traditional business practices of selling electricity. If Mississippi Power does not remain a low-cost producer and provider of quality service, the Company's retail energy sales growth, as well as new long-term contracts for energy sales outside the service area, could be limited, which could significantly reduce earnings.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112, Employers' Accounting for Postemployment Benefits, which must be effective by 1994. The new standard requires that all types of benefits provided to former or inactive employees and their families prior to retirement be accounted for on an accrual basis. These benefits include salary continuation, severance pay, supplemental unemployment benefits, disability-related benefits, job training, and health and life insurance coverage. In 1993, Mississippi Power adopted Statement No. 112, with no material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which is effective in 1994. Statement No. 115 supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities. In January 1994, Mississippi Power adopted the new rules, with no material effect on the financial statements.
On January 1, 1993, Mississippi Power changed its methods of accounting for postretirement benefits other than pensions and income taxes. See Notes 2 and 9 to the financial statements regarding the impact of these changes.
FINANCIAL CONDITION
OVERVIEW
The principal changes in Mississippi Power's financial condition during 1993 were gross property additions of $140 million to utility plant, a significant lowering of cost of capital through refinancings, and the resolution of PEP and ratepayer litigation. Funding for gross property additions came primarily from capital contributions from The Southern Company, 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 1993 by issuing new debt and equity securities and retiring high- cost issues. The Company sold $132 million of first mortgage bonds, preferred stock and, through public authorities, pollution control revenue bonds. Retirements, including maturities during 1993, totaled some $101 million of such securities. (See the Statements of Cash Flows for further details.) Composite financing rates for the years 1991 through 1993 as of year-end were as follows:
II-186 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1993 Annual Report
CAPITAL STRUCTURE
At year-end 1993, the Company's ratio of common equity to total capitalization was 49.8 percent, compared to 47.3 percent in 1992 and 44.4 percent in 1991. The increase in the ratio in 1993 can be attributed primarily to the receipt of $30 million of capital contributions from The Southern Company.
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The Company's projected construction expenditures for the next three years total $256 million ($96 million in 1994, $62 million in 1995, and $98 million in 1996). The major emphasis within the construction program will be on complying with Clean Air Act regulations, completion of a 78-megawatt combustion turbine, and upgrading existing facilities. The estimates for property additions for the three-year period include $39 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 $51 million will be required by the end of 1996 for present sinking fund requirements and maturities of long-term debt. Mississippi Power plans to continue, when economically feasible, to retire high-cost debt and preferred stock and replace these obligations with lower-cost capital.
ENVIRONMENTAL MATTERS
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were 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 must be implemented 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.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate 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 allocating 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 market for emission allowances is developing more slowly than expected. However, The Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at the eight affected plants by switching to low-sulfur coal, and this has required some equipment upgrades. This compliance strategy is expected to result in unused emission allowances being banked for later use. Additional construction expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment would be installed on all fossil-fired units. Under this Phase I compliance approach, additional construction expenditures are estimated to total approximately $275 million through 1995 for The Southern Company, of which Mississippi Power's portion is approximately $60 million.
Phase II compliance costs are expected to be higher because requirements are stricter and all fossil-fired generating plants are affected. For 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 for The Southern Company could require total construction expenditures ranging from approximately $450 million to $800 million,
II-187 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1993 Annual Report
of which Mississippi Power's portion is approximately $25 million. However, the full impact of Phase II compliance cannot now be determined with certainty, pending the 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 3 percent in revenue requirements from customers could be necessary to fully recover The Southern 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.
Mississippi Power's ECO Plan is designed to allow recovery of costs of compliance with the Clean Air Act, as well as other environmental statutes and regulations. The MPSC reviews environmental projects and the Company's environmental policy through the ECO Plan. Under the ECO Plan, any increase in the annual revenue requirement is limited to 2 percent of retail revenues. However, the plan also provides for carryover of any amount over the 2 percent limit into the next year's revenue requirement. Mississippi Power's management believes that the ECO Plan will provide 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 study will serve as the basis for 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 is expected to take some action on this issue in 1994. 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 1994 or 1995, the EPA is expected to issue revised rules on air quality control regulations related to stack height requirements of the Clean Air Act. The full impact of the final rules cannot be determined at this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal ash. However, the EPA has until 1998 to classify co-managed utility wastes -- coal ash and other utility wastes -- as either non-hazardous or hazardous. If the EPA classifies the co-managed wastes as hazardous, then substantial additional costs for the management of such wastes may be required. The full impact of any change in the regulatory status will depend on the subsequent development of co-managed waste requirements.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur costs to clean up properties currently or previously owned. The Company conducts studies to determine the extent of any required clean-up costs and has recognized in the financial statements costs to clean up known sites.
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; and the Comprehensive Environmental Response, Compensation, and Liability 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 1993 Annual Report
potential for lawsuits alleging damages caused by electromagnetic fields exists.
SOURCES OF CAPITAL
At December 31, 1993, the Company had $70 million of committed credit in revolving credit agreements and also had $21 million of committed short-term credit lines. The $40 million of notes payable outstanding at year end 1993 were apart from the committed credit facilities.
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.
II-189
STATEMENTS OF INCOME For the Years Ended December 31, 1993, 1992, and 1991 Mississippi Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS For the Years ended December 31, 1993, 1992, and 1991 Mississippi Power Company 1993 Annual Report
( ) Denotes use of cash. The accompanying notes are an integral part of these statements.
II-191
BALANCE SHEETS At December 31, 1993 and 1992 Mississippi Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS At December 31, 1993 and 1992 Mississippi Power Company 1993 Annual Report
II-193
STATEMENTS OF CAPITALIZATION At December 31, 1993 and 1992 Mississippi Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
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STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993, 1992, and 1991 Mississippi Power Company 1993 Annual Report
STATEMENTS OF PAID-IN CAPITAL For the Years Ended December 31, 1993, 1992, and 1991
The accompanying notes are an integral part of these statements.
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NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 1993 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 Electric International (Southern Electric), Southern Nuclear Operating Company (Southern Nuclear), and various other subsidiaries related to foreign utility operations and domestic non-utility operations. 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 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.
The Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both The Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. Mississippi Power is also subject to regulation by the FERC and the Mississippi Public Service Commission (MPSC). The Company follows generally accepted accounting principles and complies with the accounting policies and practices prescribed by the respective commissions.
The 1991 financial statements of the Company included the accounts of Electric City Merchandise Company, Inc. (Electric City), which discontinued operations in 1991. All significant intercompany transactions were eliminated in consolidation.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
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. Revenues are adjusted for differences between the recoverable fuel and ad valorem expenses and the amounts actually recovered in current rates.
DEPRECIATION
Depreciation of the original cost of depreciable utility plant in service is provided by using composite straight-line rates which approximated 3.1 percent in 1993 and 3.3 percent in 1992 and 1991. 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.
In years prior to 1993, income taxes were accounted for and reported under Accounting Principles Board Opinion No. 11. 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 9 to the financial statements for additional information about Statement No. 109.
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NOTES (continued) Mississippi Power Company 1993 Annual Report
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rates used to capitalize the cost of funds devoted to construction were 6.8 percent in 1993, 8.2 percent in 1992, and 9.8 percent in 1991. AFUDC (net of income taxes), as a percent of net income after dividends on preferred stock, was 3.5 percent in 1993, 2.7 percent in 1992, and 4.8 percent in 1991.
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, repair, 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 -- are shown in the table below as of December 31:
The fair value of investment securities was based on listed closing market prices. 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 used or installed.
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 $4.8 million and $4.7 million at December 31, 1993 and 1992, respectively. In 1994, an estimated 80 percent of the 1993 deferred vacation cost will be expensed, and the balance will be charged to construction and other accounts.
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NOTES (continued) Mississippi Power Company 1993 Annual Report
PROVISION FOR PROPERTY DAMAGE
Due to the significant increase in the cost of traditional insurance, effective in 1993, Mississippi Power 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 provided for the cost of storm, fire and other uninsured casualty damage by charges to income of $1.5 million in 1993, 1992, and 1991. 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, 1993, the accumulated provision amounted to $10.5 million. Regulatory treatment by the MPSC allows a maximum accumulated provision of $10.9 million.
DISCONTINUED OPERATIONS
Electric City began operating as a subsidiary of Mississippi Power in October 1987 and was formally dissolved as of December 31, 1991. Under an agreement reached in October 1991, a portion of Electric City's assets, including inventory and fixed assets, was sold to a concern independent of Mississippi Power. The remaining assets and liabilities, which were not material, were transferred to the Company.
The impact of Electric City on Mississippi Power's consolidated earnings in 1991 consisted of (a) a pretax operating loss of $10.2 million ($6.4 million after income taxes) and (b) the pretax loss of $8.7 million ($5.5 million after income taxes) resulting from the disposal of Electric City.
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 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.
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. A qualified trust for medical benefits has been established for funding amounts to the extent deductible under federal income tax regulations. Amounts funded are primarily invested in debt and equity securities. Accrued costs of life insurance benefits, other than current cash payments for retirees, currently are not being funded.
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." Because the adoption of Statement No. 106 was reflected in rates, it did not have a material impact on net income.
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 costs of such benefits recognized by the Company in 1992 and 1991 were $3.6 million and $3.0 million, respectively.
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NOTES (continued) Mississippi Power Company 1993 Annual Report
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. Retiree medical and life insurance information is shown only for 1993 because Statement No. 106 was adopted as of January 1, 1993, on a prospective basis. The funded status of the plans at December 31 was as follows:
The weighted average rates assumed in the above actuarial calculations were:
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 11.3 percent for 1993, 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 by 1.0 percent would increase the accumulated medical benefit obligation as of December 31, 1993, by $6.4 million and the aggregate of the service and interest cost components of the net retiree medical cost by $722 thousand.
Components of the plans' net cost are shown below:
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NOTES (continued) Mississippi Power Company 1993 Annual Report
Of the above net pension amounts recorded, ($170 thousand) in 1993, $269 thousand in 1992, and $576 thousand in 1991 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Of the above net postretirement medical and life insurance costs recorded in 1993, $3.9 million was charged to operating expense and the remainder was charged to construction and other accounts.
3. LITIGATION AND REGULATORY MATTERS:
RETAIL RATE ADJUSTMENT PLANS
Mississippi Power's retail base rates have been set under a Performance Evaluation Plan (PEP) since 1986. During 1993, all matters related to the original PEP case were finally resolved when the Supreme Court of Mississippi granted a joint motion to dismiss pending appeals. Also in 1993, the MPSC ordered Mississippi Power to review and propose changes to the plan that would reduce the impact of rate changes on the customer and provide incentives for Mississippi Power to keep customer prices low. In response, Mississippi Power filed a revised plan and, on January 4, 1994, the MPSC approved PEP-2. The revised plan 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 performance indicators that emphasize those factors which most directly impact the customers. PEP-2 provides for semiannual evaluations of Mississippi's performance-based return on investment, rather than on common equity as previously calculated. As in previous plans, any change in rates is limited to 2 percent of retail revenues per evaluation period before a public hearing is required. PEP-2 will remain in effect until the MPSC modifies or terminates the plan.
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 resulted in an annual retail rate increase of $2.6 million effective April 1993.
FERC REVIEWS EQUITY RETURNS AND OTHER REGULATORY MATTERS
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 8 under "Lease Agreements." Any changes in rate of return on common equity that may occur as a result of this proceeding would be effective 60 days after a proper notice of the proceeding is published. A notice was published on May 10, 1991.
In August 1992, an 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.
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 Mississippi Power's financial statements.
In 1988, the Company and its operating affiliates filed with the FERC a contract governing the pricing and other aspects of power transactions among the companies. In 1989, the FERC ordered hearings on the contract and made revenues collected under the contract subject to refund. In 1992, the
II-200 NOTES (continued) Mississippi Power Company 1993 Annual Report
FERC ruled that certain production costs under the contract had not been properly classified and ordered that the contract be revised and that refunds be made. Under reconsideration, the FERC determined that refunds were not necessary and ordered that its mandated changes in computing certain expenses under the system interchange contract become effective in August 1993. The changes mandated by the FERC will not materially affect the Company's net income.
WHOLESALE RATE FILING
On September 1, 1993, Mississippi Power filed a $3.6 million wholesale rate increase request with the FERC. Prior to this filing, the Company conferred and negotiated a settlement with all of its wholesale all requirements customers, who have executed a Settlement Agreement and Certificates of Concurrence to be included in this filing with the FERC. The Company is awaiting a response from the FERC.
RETAIL RATEPAYERS' SUITS CONCLUDED
In 1989, three retail ratepayers of the Company filed a civil complaint in the U.S. District Court for the Southern District of Mississippi against Mississippi Power and other parties. The complaint alleged that Mississippi Power obtained excessive rate increases by improper accounting for spare parts and sought actual damages estimated to be at least $10 million, plus treble and punitive damages, on behalf of all retail ratepayers of the Company for alleged violations of the federal Racketeer Influenced and Corrupt Organizations Act, federal and state antitrust laws, other federal and state statutes, and common law fraud. Mississippi Power also was named as a defendant, together with other parties in a similar civil action filed in the U.S. District Court for the Northern District of Florida. The defendants' motions for dismissal were granted by the courts, resolving these suits.
4. CONSTRUCTION PROGRAM:
Mississippi Power is engaged in continuous construction programs, the costs of which are currently estimated to total some $96 million in 1994, $62 million in 1995, and $98 million in 1996. These estimates include AFUDC of $1.6 million in 1994, $1.6 million in 1995, and $2.7 million in 1996.
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 baseload generating plants under construction. However, the construction of a combustion turbine generation unit of 78 megawatts was completed in February 1994. 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 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 Management's Discussion and Analysis under "Sources of Capital" for information regarding the Company's coverage requirements.
At December 31, 1993, Mississippi Power had committed credit agreements (360 day committed lines) with banks for $21 million. Additionally, Mississippi Power had $70 million of unused committed credit agreements in the form of revolving credit agreements expiring December 1, 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 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.
As of December 31, 1993, Mississippi Power had $40 million in short-term bank borrowings all of which were made apart from committed credit arrangements. II-201 NOTES (continued) Mississippi Power Company 1993 Annual Report
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.
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 $243 million at December 31, 1993. 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 December 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 including the current portion totaled $18 million at December 31, 1993.
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, 1993, Mississippi Power's percentage ownership and investment in these jointly owned facilities were as follows:
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. 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 January 1989. However, the Company continues to participate in transmission and energy sales under the unit power sales agreements. The other agreements (other long-term sales) are non-firm commitments and are based on capacity of the system in general. 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:
Long-term non-firm power of 400 megawatts was sold in 1993 by the Southern electric system to Florida Power Corporation. In January 1994, this amount decreased to 200 megawatts, and the contract will expire at year-end. II-202
NOTES (continued) Mississippi Power Company 1993 Annual Report
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, subsidiaries of The Southern Company entered into a settlement agreement with Gulf States that resolved litigation between the companies that had been pending since 1986 and arose out of a dispute over certain unit power and other long-term power sales contracts. In 1993, all remaining terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received -- less the amounts previously included in income -- Mississippi Power recorded an increase in net income of approximately $2.6 million in 1991.
8. LEASE AGREEMENTS:
In 1984, Mississippi Power and 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. In 1993, 1992, and 1991 the use fees collected under the agreement, net of related expenses, amounted to $3.9 million, $3.9 million and $4.0 million, respectively, and are included with other income, net, in the Statements of Income. For other information see Note 3 under "FERC Reviews Equity Returns and Other Regulatory Matters."
In 1989, Mississippi Power entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars to transport coal to Plant Daniel. Gulf Power, as joint owner of Plant Daniel, is responsible for one half of the lease costs. The Company's share of the lease is charged to fuel inventory and allocated to fuel expense as the fuel is used. The lease costs charged to inventory were $1.2 million in 1993, $1.2 million for 1992 and $1.3 million for 1991. For the year 1994, the Company's annual lease payment will be $1.2 million. The Company's annual lease payment for 1995 will be $2.4 million and for 1996, 1997, and in 1998 the payment will be $1.2 million. Lease payments after 1998 total approximately $17.4 million. The Company has the option after three years to purchase the railcars at the greater of termination value or fair market value. Additionally, at the end of the lease term, Mississippi Power has the option to renew the lease.
9. INCOME TAXES:
Effective January 1, 1993, Mississippi Power adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption of Statement No. 109 resulted in cumulative adjustments that had no effect on net income. The adoption also resulted in the recording of additional deferred income taxes and related assets and liabilities. The related assets of $25 million are revenues to be received from customers. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. The related liabilities of $48 million are revenues to be refunded to customers. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and unamortized investment tax credits. Additionally, deferred income taxes related to accelerated tax depreciation previously shown as a reduction to utility plant were reclassified.
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NOTES (continued) Mississippi Power Company 1993 Annual Report
Details of the federal and state income tax provisions are shown below:
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:
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. At December 31, 1993, this tax rate differential was 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 1993, $1.4 million in 1992 and $1.5 million in 1991. At December 31, 1993, all investment tax credits available to reduce federal income taxes payable had been utilized.
II-204 NOTES (continued) Mississippi Power Company 1993 Annual Report
The total provision for income taxes as a percentage of pre-tax income and the differences between those effective rates and the statutory federal tax rates were as follows:
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.
10. OTHER LONG-TERM DEBT:
Details of other long-term debt are as follows:
Pollution control obligations represent installment or lease purchases of pollution control facilities financed by application of funds derived from sales by public authorities of tax-exempt revenue bonds. Mississippi Power has authenticated and delivered to the Trustee a like principal amount of first mortgage bonds as security for obligations under collateralized installment agreements. The principal and interest on the first mortgage bonds will be payable only in the event of default under these agreements. The 5.8% Series of pollution control obligations has a cash sinking fund requirement of $10 thousand annually through 1997 and $20 thousand in 1998.
At December 31, 1993, under "Other Property and Investments" approximately $6 million related to the 6.20% Series of Pollution Control Obligations remains available for completion of certain solid waste disposal facilities.
The 8.25 percent notes payable relate to the termination of two coal contracts. See Note 5 under "Fuel Commitments" for information on these coal contracts.
The annual estimated maturities of total notes payable are $8.8 million in 1994 and $10.8 million in 1995.
II-205
NOTES (continued) Mississippi Power Company 1993 Annual Report
11. LONG-TERM DEBT DUE WITHIN ONE YEAR:
A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year is as follows:
The first mortgage bond improvement fund requirement is one percent of each outstanding series authenticated under the indenture of Mississippi Power prior to January 1 of each year, other than first mortgage bonds issued as collateral security for certain pollution control obligations. The requirement must be satisfied by June 1 of each year by depositing cash or reacquiring bonds, or by pledging additional property equal to 166-2/3 percent of such requirement.
12. COMMON STOCK DIVIDEND RESTRICTIONS:
Mississippi Power's first mortgage bond indenture and the Articles of Incorporation contain various common stock dividend restrictions. At December 31, 1993, $86 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 Articles of Incorporation.
13. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial data for 1993 and 1992 are as follows:
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 1993 Annual Report
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II-208
II-209
II-210
STATEMENTS OF INCOME Mississippi Power Company
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STATEMENTS OF INCOME Mississippi Power Company
II-212
STATEMENTS OF CASH FLOWS Mississippi Power Company
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STATEMENTS OF CASH FLOWS Mississippi Power Company
II-214
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, 1993
FIRST MORTGAGE BONDS
POLLUTION CONTROL BONDS
PREFERRED STOCK
II-219
MISSISSIPPI POWER COMPANY
SECURITIES RETIRED DURING 1993
FIRST MORTGAGE BONDS
POLLUTION CONTROL BONDS
PREFERRED STOCK
II-220
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-221
MANAGEMENT'S REPORT Savannah Electric and Power Company 1993 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. /s/ K. R. Willis - -------------------------------- ------------------------------------- Arthur M. Gignilliat, Jr. K. R. Willis President Vice-President and Chief Executive Officer Treasurer and Chief Financial Officer
II-222 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF SAVANNAH ELECTRIC AND POWER COMPANY:
We have audited the accompanying balance sheets and statements of capitalization of Savannah Electric and Power Company (a Georgia corporation) as of December 31, 1993 and 1992, 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, 1993. 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-231 through II-244) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 1993 and 1992, 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 & Co.
Atlanta, Georgia, February 16, 1994
II-223 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 1993 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred stock for 1993 totaled $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.
In 1992, earnings were $20.5 million, representing a $3.5 million (14.6 percent) decrease from the prior year. This decrease resulted primarily from increases in maintenance and administrative and general expenses, partially offset by a 4.6 percent increase in retail operating revenues. Operating revenues increased despite the negative impact of a $2.8 million annual reduction in retail base rates effective in June 1992, and mild weather.
REVENUES
Total revenues for 1993 were $218.4 million, reflecting a 10.5 percent increase over 1992, primarily due to an increase in retail energy sales.
The following table summarizes the factors impacting operating revenues compared to the prior year for the 1991-1993 period:
Total retail revenues increased 11.5 percent in 1993, compared to a 4.6 percent increase in 1992. The increase in 1993 retail revenues attributable to growth in both retail customers and average use per customer was enhanced by exceptionally hot weather during the summer. The substantial increase in fuel cost recovery and other revenues reflects increases in net generation and the unit cost of purchased power. The increase in 1992 retail revenues resulted from growth in both retail customers and average use per customer, but was substantially offset by mild weather and the June 1992 base rate reduction.
II-224 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1993 Annual Report
Under the Company's fuel cost recovery provisions, fuel revenues equal fuel expense, including the fuel and capacity components of purchased energy, and have no effect on earnings. Revenues from sales to non-affiliated utilities 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:
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.
Kilowatt-hour sales for 1993 and the percent change by year were as follows:
The increases in energy sales in 1993 and 1992 continue to reflect a growing customer base, an increase in average energy sales per customer, and improved economic conditions in the Company's service area. Sales were enhanced in 1993 by temperature extremes in the summer months and in December.
EXPENSES
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 weather and higher cost fuel sources. In 1992 an increase in purchased power reflected a 15.4 percent decrease in generation compared to 1991. Despite the decrease in generation, total 1992 fuel expenses were substantially unchanged from the prior year reflecting generation from higher cost fuel sources.
The increase in other operation expenses reflects a $4.5 million cost associated with a one-time charge related to a work force reduction program. The Company also recognized higher employee benefits costs under new accounting rules adopted in 1993. See Note 2 to the financial statements for additional information on these new rules. In 1992, the increase in other operation expenses was primarily a result of increases in outside services and administrative and general expenses, which reflected higher employee training and benefits expenses. Total interest expense on long-term debt was reduced by 5.4 percent in 1992, as the Company refinanced higher-cost debt.
II-225 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1993 Annual Report
The mix of energy supply is determined primarily by system load, the unit cost of fuel consumed and the availability of units.
The amount and sources of energy supply and the average cost of fuel per net kilowatt-hour generated and purchased power were as follows:
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 regulatory matters.
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) will have a profound 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 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, pressure for legislation to allow retail wheeling will continue. The Company is preparing now to meet the challenge of these major changes in the traditional business practices of selling electricity. If the Company does not remain a low-cost producer and provide quality service, the Company's retail energy sales growth, as well as new long-term contracts for energy sales outside the service area, could be limited, and this could significantly erode earnings.
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. Expansion and increased utilization of these programs will be contingent upon sharing of cost savings between the customers and the Company. Besides promoting energy efficiency, another benefit of these programs could be the ability to defer the need to construct baseload generating facilities further into the future. The ability to defer major construction projects, in conjunction with the precertification approval process for such projects by the Georgia Public Service Commission (GPSC), will
II-226 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1993 Annual Report
diminish the possible exposure to prudency disallowances and the resulting impact on earnings.
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 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 includes 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.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112, Employers' Accounting for Postemployment Benefits, which must be implemented by 1994. The new standard requires that all types of benefits provided to former or inactive employees and their families prior to retirement be accounted for on an accrual basis. These benefits include salary continuation, severance pay, supplemental unemployment benefits, disability-related benefits, job training, and health and life insurance coverage.
The FASB has issued Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which is effective in 1994. Statement No. 115, supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities. The Company adopted the new rules January 1, 1994, with no material effect on the financial statements.
On January 1, 1993, the Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes. See notes 2 and 7 to the financial statements regarding the impact of these changes.
FINANCIAL CONDITION
OVERVIEW
The principal change in the Company's financial condition in 1993 was additions of $73 million to utility plant. The majority of funds needed for gross property additions since 1990 have been provided from operating activities, principally from earnings and non-cash charges to income such as depreciation and deferred income taxes. See Statements of Cash Flows for additional information.
CAPITAL STRUCTURE
As of December 31, 1993, the Company's capital structure consisted of 45.3 percent common equity, 10.3 percent preferred stock and 44.4 percent long-term debt, excluding amounts due within one year. The Company's long-term financial objective for capitalization ratios is to maintain a capital structure of common equity at 45 percent, preferred stock at 10 percent and debt at 45 percent.
Maturities and retirements of long-term debt were $4 million in 1993, $53 million in 1992 and $23 million in 1991.
In November 1993, the Company issued 1,400,000 shares of 6.64 percent series preferred stock. In December 1993, the Company redeemed all 800,000 shares outstanding of its 9.5 percent series preferred stock at the prescribed redemption price of $26.57 plus accrued dividends.
The composite interest rates for the years 1991 through 1993 as of year-end were as follows:
II-227 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1993 Annual Report
The Company's current securities ratings are as follows:
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The Company's projected construction expenditures for the next three years total $98 million ($33 million in 1994, $32 million in 1995, and $33 million in 1996). 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. The largest project during this period is the addition of two 80 megawatt combustion turbine units, to be placed into service in 1994. The estimated cost of this project is $61 million. The Company is also constructing six combustion turbine units for Georgia Power Company.
OTHER CAPITAL REQUIREMENTS
In addition to the funds needed for the construction program, approximately $5.9 million will be needed by the end of 1996 for present sinking fund requirements and maturities.
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 -- will 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 must be implemented 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.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate 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 allocating 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 market for emission allowances is developing slower than expected. However, The Southern Company's sulfur dioxide compliance strategy is designed to take advantage of allowances as the market develops.
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 construction expenditures are required to install equipment for the control of nitrogen oxide emissions at these eight plants. Also, continuous emissions monitoring equipment would be installed on all fossil-fired units. Under this Phase I compliance approach, additional construction expenditures are estimated to total approximately $275 million through 1995 for The Southern Company, of which the Company's portion is approximately $2 million.
Phase II compliance costs are expected to be higher because requirements are stricter and all fossil-fired generating plants are affected. For 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, compliance could require total construction expenditures ranging from approximately $450 million to $800 million of which the Company's portion is expected to be approximately $25 million. However, the full impact of
II-228 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1993 Annual Report
Phase II compliance cannot now be determined with certainty, pending the 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 5 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.
There can be no assurance that all Clean Air Act costs will be recovered.
Title III of the Clean Air Act requires a multi-year EPA study of power plant emissions of hazardous air pollutants. The study will serve as the basis for 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 is expected to take some action on this issue in 1994. 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 matters, 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 1994 or 1995, the EPA is expected to 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.
Savannah Electric and Power 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 will recognize in the financial statements any costs to clean up known sites.
Several major pieces of environmental legislation are in the process of being reauthorized or amended by Congress. These include: the Clean Water Act, the Comprehensive Environmental Response, Compensation, and Liability Act, and the Resource Conservation and Recovery 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 Southern 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, 1993, the Company had $3.9 million of cash and $14.5 million of unused credit arrangements with banks to meet its short-term cash needs. The Company had $3 million of short-term bank borrowings at December 31, 1993. In January 1994, the Company renegotiated a two-year revolving credit arrangement with four of its
II-229 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 1993 Annual Report
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 combustion turbine construction program.
It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived from operations and the sale of additional first mortgage bonds and preferred stock and capital contributions from 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.
II-230 STATEMENTS OF INCOME For the Years Ended December 31, 1993, 1992, and 1991 Savannah Electric and Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-231
STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993, 1992, and 1991 Savannah Electric and Power Company 1993 Annual Report
( ) Denotes use of cash. The accompanying notes are an integral part of these statements.
II-232
BALANCE SHEETS At December 31, 1993 and 1992 Savannah Electric and Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-233
BALANCE SHEETS At December 31, 1993 and 1992 Savannah Electric and Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-234
STATEMENTS OF CAPITALIZATION At December 31, 1993 and 1992 Savannah Electric and Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-235
STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993, 1992, and 1991 Savannah Electric and Power Company 1993 Annual Report
The accompanying notes are an integral part of these statements.
II-236
NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 1993 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 Electric International (Southern Electric), Southern Nuclear Operating Company (Southern Nuclear), and various other subsidiaries related to foreign utility operations and domestic non-utility operations. At this time, the operations of the other subsidiaries are not material. 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 to the subsidiary companies. 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.
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.
REVENUES AND FUEL COSTS
The Company accrues revenues for services rendered but unbilled at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The Company's electric rates include provisions to adjust billings for fluctuations in capacity and the energy components of purchased power costs. Revenues include the actual cost of fuel and purchased power incurred.
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 1993 and 3.2 percent in 1992, and 1991. The decrease in 1993 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.
In years prior to 1993, income taxes were accounted for and reported under Accounting Principles Board Opinion No. 11. 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.
II-237 NOTES (continued) Savannah Electric and Power Company 1993 Annual Report
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The composite rates used by the Company to calculate AFUDC were 8.77 percent in 1993, 11.27 percent in 1992, and 11.38 percent in 1991.
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, items for which the carrying amount does not approximate fair value must be disclosed. At December 31, 1993, the fair value of long-term debt was $164 million and the carrying amount was $154 million. The fair value of long-term debt was $117 million and the carrying amount was $109 million at December 31, 1992. 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.
2. RETIREMENT BENEFITS
PENSION PLANS
The Company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. Benefits under this plan reflect the employee's years of service, age at retirement and average compensation for the three years immediately preceding retirement. 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 fund are primarily invested in equity and debt 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 has been established for funding amounts to the extent deductible under federal income tax regulations. Accrued costs of life insurance benefits, other than current cash payments for retirees, currently are not being funded.
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."
II-238 NOTES (continued) Savannah Electric and Power Company 1993 Annual Report
Consistent with regulatory treatment, the Company recognized these costs on a cash basis as payments were made in 1992 and 1991. The total costs of such benefits recognized by the Company amounted to $375 thousand in 1992 and $487 thousand in 1991.
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 Statements Nos. 87 and 106, respectively. Retiree medical and life insurance information is shown for 1993 only because Statement No. 106 was adopted as of January 1, 1993, on a prospective basis. The funded status of the plans at December 31 was as follows:
The weighted average rates assumed in the actuarial calculations were:
In accordance with Statement No. 87, an additional liability related to under-funded accumulated benefit obligations was recognized at December 31, 1993. A corresponding net-of-tax charge of $2.1 million was recognized as a separate component of Common Stock Equity in the Statements of Capitalization.
The assumption used in measuring the accumulated postretirement medical benefit obligation was a weighted average medical care cost trend rate of 11.3 percent for 1993, 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 by 1.0 percent would increase the accumulated medical benefit obligation as of December 31, 1993, by $1.7 million and the aggregate of the service and interest cost components of the net retiree medical cost by $0.2 million.
II-239 NOTES (continued) Savannah Electric and Power Company 1993 Annual Report
Components of the plans' net costs are shown below:
Of the above net pension amounts, $2.0 million in 1993, $1.7 million in 1992 and $1.5 million in 1991 were recorded in operating expenses, and the remainder was recorded in construction and other accounts.
Net postretirement medical and life insurance costs of $1.8 million in 1993 were charged to operating expenses.
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 1993, 1992 and 1991 were $980 thousand, $316 thousand and $338 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
The Company has 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
RATE 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 $33 million in 1994, $32 million in 1995 and $33 million in 1996. The estimates include AFUDC of $1.6 million in 1994, $0.6 million in 1995 and $0.7 million in 1996. 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 cost of capital. The construction of two combustion turbine peaking units totaling 160 megawatts is planned to be completed in mid 1994. The Company is also constructing six combustion turbine peaking units owned by Georgia Power Company. The construction is to be completed in 1996.
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.
II-240 NOTES (continued) Savannah Electric and Power Company 1993 Annual Report
5. FINANCING AND COMMITMENTS
GENERAL
To the extent possible, the Company's construction program is expected to be financed from internal sources and from the issuance of additional long-term debt and 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 1994, unused credit arrangements with four banks totaled $14.5 million, and expire at various times during 1994.
The Company has $20 million of revolving credit arrangements expiring December 31, 1995. These agreements allow short-term borrowings to be converted into term loans, payable in 12 equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at the Company's option. In connection with these credit arrangements, the Company agrees to pay commitments fees based on the unused portions of the commitments.
In connection with all other lines of credit, the Company has the option of paying fees or maintaining compensating balances, which are substantially all the cash of the Company except for daily working funds and similar items. These balances are not legally restricted from withdrawal.
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, $1.5 million, and $1.4 million for 1993, 1992, and 1991, respectively. At December 31, 1993, estimated future minimum lease payments for non-cancelable operating leases were as follows:
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. Certain of these agreements are non-firm and are based on capacity of the system in general. Other agreements are firm and pertain to the 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 portion of capacity revenues has been as follows:
Long-term non-firm power of 400 megawatts was sold by the Southern electric system in 1993 to Florida Power Corporation (FPC). In January 1994, this amount decreased to 200 megawatts, and the contract will expire at year-end.
II-241 NOTES (continued) Savannah Electric and Power Company 1993 Annual Report
7. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income Taxes. The adoption of Statement No. 109 resulted in cumulative adjustments that had no material effect on net income. The adoption also resulted in the recording of additional deferred income taxes and related assets and liabilities. The related assets of $25 million are revenues to be received from customers. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized AFUDC. The related liabilities of $26 million are revenues to be refunded to customers. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and unamortized investment tax credits. Additionally, deferred income taxes related to accelerated tax depreciation previously shown as a reduction to utility plant were reclassified.
Details of the federal and state income tax provisions are as follows:
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:
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 1993, 1992 and 1991. At December 31, 1993, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the effective income tax rate to the statutory tax rate is as follows:
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.
II-242 NOTES (continued) Savannah Electric and Power Company 1993 Annual Report
8. CUMULATIVE PREFERRED STOCK
In November 1993, the Company issued 1,400,000 shares of 6.64 percent Series Preferred stock which has redemption provisions of $26.66 per share plus accrued dividends if on or prior to November 1, 1998, and at $25 per share plus accrued dividends thereafter.
In December 1993, the Company redeemed all 800,000 shares outstanding of its 9.5 percent 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.
On February 19, 1993, the Company refunded its $4.1 million, 6.25 percent Series Pollution Control Bonds, due 1998 with $4.1 million of variable rate Series Pollution Control Bonds due 2016.
In 1994, there is a first mortgage bond maturity of $3.7 million. The sinking fund requirements of first mortgage bonds are being satisfied by certification of property additions. See Note 10 "Long-Term Debt Due Within One Year" for details.
Details of other long-term debt are as follows:
Sinking fund requirements and /or maturities through 1998 applicable to long-term debt are as follows: $4.5 million in 1994; $0.7 million in 1995; $0.7 million in 1996; $0.1 million in 1997 and no requirement is needed for 1998.
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 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.
II-243 NOTES (continued) Savannah Electric and Power Company 1993 Annual Report
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 is as follows:
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 the preferred and common stocks. At December 31, 1993, approximately $55 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 1993 and 1992 are as follows (in thousands):
The Company's business is influenced by seasonal weather conditions, a seasonal rate structure and the timing of rate changes, among other factors.
II-244
SELECTED FINANCIAL AND OPERATING DATA Savannah Electric and Power Company 1993 Annual Report
Note: NR = Not Rated
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SELECTED FINANCIAL AND OPERATING DATA Savannah Electric and Power Company 1993 Annual Report
II-246 SELECTED FINANCIAL AND OPERATING DATA (continued) Savannah Electric and Power Company 1993 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA (continued) Savannah Electric and Power Company 1993 Annual Report
II-248
STATEMENTS OF INCOME Savannah Electric and Power Company
* Tax-free common stock/bond exchange
II-249
STATEMENTS OF INCOME Savannah Electric and Power Company
II-250
STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
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STATEMENTS OF CASH FLOWS Savannah Electric and Power Company
II-252
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
II-256
SAVANNAH ELECTRIC AND POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
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SAVANNAH ELECTRIC AND POWER COMPANY
SECURITIES RETIRED DURING 1993
POLLUTION CONTROL BONDS
II-258 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 1994 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 54 Served as Director since 3-1-89.
BILL M. GUTHRIE Executive Vice President of ALABAMA Age 60 Served as Director since 12-16-88
EDWARD L. ADDISON (2) Age 63 Served as Director since 11-1-83
WHIT ARMSTRONG (2) Age 46 Served as Director since 9-24-82
PHILIP E. AUSTIN (2) Age 52 Served as Director since 1-25-91
MARGARET A. CARPENTER (2) Age 69 Served as Director since 2-26-93
PETER V. GREGERSON, SR. (2) Age 65 Served as Director since 10-22-93
CRAWFORD T. JOHNSON, III (2) Age 68 Served as Director since 4-18-69
CARL E. JONES, JR. (2) Age 53 Served as Director since 4-22-88
WALLACE D. MALONE, JR. (2) Age 57 Served as Director since 6-22-90
WILLIAM V. MUSE (2) Age 54 Served as Director since 2-26-93
JOHN T. PORTER (2) Age 62 Served as Director since 10-22-93
GERALD H. POWELL (2) Age 67 Served as Director since 2-28-86
ROBERT D. POWERS (2) Age 43 Served as Director since 1-24-92
JOHN W. ROUSE (2) Age 56 Served as Director since 4-22-88
WILLIAM J. RUSHTON, III (2) Age 64 Served as Director Since 9-18-70
JAMES H. SANFORD (2) Age 49 Served as Director since 8-1-83
JOHN C. WEBB, IV (2) Age 51 Served as Director since 4-22-77
LOUIS J. WILLIE (2) Age 70 Served as Director since 3-23-84
JOHN W. WOODS (2) Age 62 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 23, 1993) for
III-1 meeting of ALABAMA's stockholder (April 23, 1993) for one year until the next annual meeting or until a successor is elected and qualified, except for the individuals elected in October 1993. 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 54 Served as Executive Officer since 3-1-89
BANKS H. FARRIS Senior Vice President Age 59 Served as Executive Officer since 12-3-91
WILLIAM B. HUTCHINS, III Senior Vice President and Chief Financial Officer Age 50 Served as Executive Officer since 12-3-91
T. HAROLD JONES Senior Vice President Age 63 Served as Executive Officer since 12-1-91
CHARLES D. MCCRARY Senior Vice President Age 42 Served as Executive Officer since 1-1-91
(1) Previously served as executive officer of ALABAMA from 1979 to 1985.
Each of the above is currently an executive officer of ALABAMA, serving a term running from the last annual meeting of the directors (April 23, 1993) 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.
EDWARD L. ADDISON - Elected in 1983; President of SOUTHERN from 1983 until elected Chairman of the Board in 1994. Director of SOUTHERN, GEORGIA, Phelps Dodge Corporation, Protective Life Corporation, Wachovia Bank of Georgia, N.A., Wachovia Corporation of Georgia and CSX Corporation.
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.
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 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.
LOUIS J. WILLIE - Chairman of the Board and President of Booker T. Washington Insurance Co. Director of SOUTHERN.
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 Vice President - Human Resources from 1989 to 1991 and Division Vice President from 1985 to 1989.
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 Vice President and Treasurer from 1983 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.
CHARLES D. MCCRARY - Elected in 1991; responsible for the External Relations Department, Operating Services and Corporate Services. Also, assumes responsibility for financial matters while Mr. Hutchins is on medical leave. He previously served as Vice President of Administrative Services - Nuclear of SCS from 1988 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 49 Served as Director since 1-1-94.
WARREN Y. JOBE Executive Vice President, Treasurer and Chief Financial Officer. Age 53 Served as Director since 8-1-82
EDWARD L. ADDISON (1) Age 63 Served as Director since 11-1-83
BENNETT A. BROWN (1) Age 64 Served as Director since 5-15-80
WILLIAM P. COPENHAVER (1) Age 69 Served as Director since 6-18-86
A. W. DAHLBERG (1) Age 53 Served as Director since 6-1-88
WILLIAM A. FICKLING, JR. (1) Age 61 Served as Director since 4-18-73
L. G. HARDMAN, III (1) Age 54 Served as Director since 6-25-79
JAMES R. LIENTZ, JR. (1) Age 50 Served as Director since 7-1-93
WILLIAM A. PARKER, JR. (1) Age 66 Served as Director since 5-19-65
G. JOSEPH PRENDERGAST (1) Age 48 Served as Director since 1-20-93
HERMAN J. RUSSELL (1) AGE 63 Served as Director since 5-18-88
GLORIA M. SHATTO (1) Age 62 Served as Director since 2-20-80
ROBERT STRICKLAND (1) Age 66 Served as Director since 11-21-79
WILLIAM JERRY VEREEN (1) Age 53 Served as Director since 5-18-88
THOMAS R. WILLIAMS (1) Age 65 Served as Director since 3-17-82
(1) No position other than Director.
Each of the above is currently a director of GEORGIA, serving a term running from the last annual meeting of GEORGIA's stockholder (May 19, 1993) for one year until the next annual meeting or until a successor is elected and qualified, except Messrs. Franklin and Lientz.
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 49 Served as Executive Officer since 1-1-94
WARREN Y. JOBE Executive Vice President, Treasurer, Chief Financial Officer and Director Age 53 Served as Executive Officer since 5-19-82
III-4
DWIGHT H. EVANS Executive Vice President - External Affairs Age 45 Served as Executive Officer since 4-19-89
GENE R. HODGES Executive Vice President - Customer Operations Age 55 Served as Executive Officer since 11-19-86
KERRY E. ADAMS Senior Vice President - Fossil and Hydro Power Age 49 Served as Executive Officer since 5-1-89
WAYNE T. DAHLKE Senior Vice President - Power Delivery Age 53 Served as Executive Officer since 4-19-89
JAMES K. DAVIS Senior Vice President - Corporate Relations Age 53 Served as Executive Officer since 10-1-93
ROBERT H. HAUBEIN Senior Vice President - Administrative Services Age 54 Served as Executive Officer since 2-19-92
GALE E. KLAPPA Senior Vice President - Marketing Age 43 Served as Executive Officer since 2-19-92
FRED D. WILLIAMS Senior Vice President - Bulk Power Markets Age 49 Served as Executive Officer since 11-18-92
Each of the above is currently an executive officer of GEORGIA, serving a term running from the last annual meeting of the directors (May 19,1993) for one year until the next annual meeting or until his successor is elected and qualified, except Messrs. Franklin and Davis.
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 Bank.
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 secretary and treasury operations.
EDWARD L. ADDISON - President of SOUTHERN from 1983 until his election as Chairman of Board in 1994. Director of SOUTHERN, ALABAMA, Wachovia Bank of Georgia, N.A., Wachovia Corporation of Georgia, Phelps Dodge Corporation, Protective Life Corporation and CSX Corporation.
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 Confederation Life Insurance Company.
WILLIAM P. COPENHAVER - Director, Arcadian Fertilizer, L.P. (agricultural and industrial chemicals). Director of SOUTHERN and Georgia Bank & Trust Company.
A. W. DAHLBERG - President of SOUTHERN effective in 1994. He previously served as President and Chief Executive Officer of GEORGIA from 1988 through 1993. Director of SOUTHERN, Trust Company Bank, Trust Company of Georgia, Protective Life Corporation and Equifax, Inc.
WILLIAM A. FICKLING, JR. - Chairman of the Board, Mulberry Street Investment Company, Macon, Georgia, and Co-chairman of Beech Street Corporation (insurance).
III-5
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. 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, and from 1987 to 1990, he was head of Corporate Bank Group of NationsBank of Georgia, N.A.
WILLIAM A. PARKER, JR. - Chairman of the Board, Cherokee Investment Company, Inc. (private investments), Atlanta, Georgia. Director of SOUTHERN, Genuine Parts Company, Life Insurance Company of Georgia, First Union Real Estate Investment Trust, Atlantic Realty Company, ING North America Insurance Company, Post Properties, Inc. and Haverty Furniture Companies, Inc.
G. JOSEPH PRENDERGAST - President and Chief Executive Officer, Wachovia Corporation of Georgia and Wachovia Bank of Georgia, N.A. since 1993. From 1988 to 1993, he served 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.
ROBERT STRICKLAND - Retired Chairman of the Board and Chief Executive Officer of SunTrust Banks, Inc. Director of Georgia US Corporation, Equifax, Inc., Life Insurance Company of Georgia, Oxford Industries, Inc. and The Investment Centre.
WILLIAM JERRY VEREEN - President and Chief Executive Officer of Riverside Manufacturing Company (manufacture and sale of uniforms), Moultrie, Georgia. Director of Gerber Garment Technology, Inc. and Textile Clothing Technology Corp.
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., and American Software, Inc.
DWIGHT H. EVANS - Executive Vice President - External Affairs since 1989. Senior Vice President - Public Affairs from 1988 to 1989.
GENE R. HODGES - Executive Vice President - Customer Operations since 1992. Senior Vice President - Region/Land Operations from 1990 to 1992. Senior Vice President - Division Operations from 1986 to 1990.
KERRY E. ADAMS - Senior Vice President - Fossil and Hydro Power since 1989.
WAYNE T. DAHLKE - Senior Vice President - Power Delivery since February 1992. Senior Vice President - Marketing from 1989 to 1992.
JAMES K. DAVIS - Senior Vice President - Corporate Relations since October 1993. Vice President of Corporate Relations from 1988 to 1993.
ROBERT H. HAUBEIN - Senior Vice President - Administrative Services since 1992. Vice President - Northern Region from 1990 to 1992. Division Vice President of ALABAMA from 1985 to 1990.
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.
D. L. MCCRARY (1) Chairman of the Board and Chief Executive Officer Age 64 Served as Director since 4-28-83
TRAVIS J. BOWDEN President Age 55 Served as Director since 2-1-94
PAUL J. DENICOLA (2) Age 45 Served as Director since 4-19-91
REED BELL, SR., M.D. (2) Age 67 Served as Director since 1-17-86
FRED C. DONOVAN, SR. (2) Age 53 Served as Director since 1-18-91
W. D. HULL, JR. (2) Age 61 Served as Director since 10-14-83
C. W. RUCKEL (2) Age 66 Served as Director since 4-20-62
J. K. TANNEHILL (2) Age 60 Served as Director since 7-19-85
(1) Retires May 1, 1994. (2) No position other than Director.
Each of the above is currently a director of GULF, serving a term running from the last annual meeting of GULF's stockholder (June 29, 1993) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Bowden.
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.
D. L. MCCRARY Chairman of the Board and Chief Executive Officer Age 64 Served as Executive Officer since 5-1-83
TRAVIS J. BOWDEN President Age 55 Served as Executive Officer since 2-1-94
F. M. FISHER, JR. Vice President - Employee and External Relations Age 45 Served as Executive Officer since 5-19-89
JOHN E. HODGES, JR. Vice President - Customer Operations Age 50 Served as Executive Officer since 5-19-89
G. EDISON HOLLAND, JR. Vice President and Corporate Counsel Age 41 Served as Executive Officer since 4-25-92
EARL B. PARSONS, JR. Vice President - Power Generation and Transmission Age 55 Served as Executive Officer since 4-14-78
A. E. SCARBROUGH Vice President - Finance Age 57 Served as Executive Officer since 9-21-77
Each of the above is currently an executive officer of GULF, serving a term running from the last annual meeting of the directors (July 23, 1993) for one year until the next annual meeting or until his successor is elected and qualified, except for Mr. Bowden.
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.
D. L. MCCRARY - Elected Chairman of the Board effective February 1994. He previously served as President and Chief Executive Officer from 1983 to 1994; responsible primarily for formation of overall corporate policy.
TRAVIS J. BOWDEN - Elected President effective February 1994 and, upon Mr. McCrary's retirement May 1994, Chief Executive Officer. He previously served as Executive Vice President of ALABAMA from 1985 to 1994.
PAUL J. DENICOLA - President and Chief Executive Officer of SCS 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.
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 July 1992. He also previously maintained a private medical practice and served as Medical Director of Children's Medical Services from 1988 to 1989.
FRED C. DONOVAN, SR. - 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 Sun Bank/West Florida, Panama City, Florida.
F. M. FISHER, JR. - Elected Vice President - Employee and External Relations in 1989. He previously served as General Manager of Central Division from 1988 to 1989.
JOHN E. HODGES, JR. - Elected Vice President - Customer Operations in 1989. He previously served as General Manager of Western Division from 1986 to 1989.
G. EDISON HOLLAND, JR. - Elected Vice President and Corporate Counsel in 1992; responsible for all legal matters associated with GULF and serves as compliance officer. Also served, 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. He previously served as Vice President - Electric Operations from 1978 to 1989.
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 45 Served as Director since 4-24-91
PAUL J. DENICOLA (1) Age 45 Served as Director since 5-1-89
EDWIN E. DOWNER (1) Age 62 Served as Director since 4-24-84
ROBERT S. GADDIS (1) Age 62 Served as Director since 1-21-86
WALTER H. HURT, III (1) Age 58 Served as Director since 4-6-82
AUBREY K. LUCAS (1) Age 59 Served as Director since 4-24-84
EARL D. MCLEAN, JR. (1) Age 68 Served as Director since 10-21-78
GERALD J. ST. Pe (1) Age 54 Served as Director since 1-21-86
LEO W. SEAL, JR. (1) Age 69 Served as Director since 4-4-67
N. EUGENE WARR (1) Age 58 Served as Director since 1-21-86
(1) No position other than Director.
Each of the above is currently a director of MISSISSIPPI, serving a term running from the last annual meeting of MISSISSIPPI's stockholder (April 6, 1993) for one year until the next annual meeting or until a successor is elected and qualified. There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of MISSISSIPPI acting solely in their capacities as such.
(b)(4) Identification of executive officers of MISSISSIPPI.
DAVID M. RATCLIFFE President, Chief Executive Officer and Director Age 45 Served as Executive Officer since 4-24-91
H. E. BLAKESLEE Vice President - Customer Services and Marketing Age 53 Served as Executive Officer since 1-25-84
THOMAS A. FANNING Vice President and Chief Financial Officer Age 37 Served as Executive Officer since 4-1-92
DON E. MASON Vice President - External Affairs and Corporate Services Age 52 Served as Executive Officer since 7-27-83
Each of the above is currently an executive officer of MISSISSIPPI, serving a term running from the last annual meeting of the directors (April 28, 1993) for one year until the next annual meeting or until his successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of MISSISSIPPI acting solely in their capacities as such.
(c)(4) Identification of certain significant employees. None.
(d)(4) Family relationships. None.
(e)(4) Business experience.
III-9
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.
EARL D. MCLEAN, JR. - Co-owner of the T. C. Griffith Insurance Agency, Inc. (insurance and real estate), Columbia, Mississippi. Director of SOUTHERN.
GERALD J. ST. Pe - President of Ingalls Shipbuilding and Corporate Vice President of Litton Industries, Inc. since 1985. Director of Merchants and Marine Bank, Pascagoula, Mississippi.
LEO W. SEAL, JR. - Chairman of the Board and Chief Executive Officer of Hancock Bank, Gulfport, Mississippi, and Chairman of the Board of Harrison Life Insurance Company. Director of Hancock Bank and Bank of Wiggins.
N. EUGENE WARR - Retailer (Biloxi and Gulfport, Mississippi.) Chairman of the Board of First Jefferson Corporation and the Jefferson Bank of 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.
THOMAS A. FANNING - Elected Vice President in 1992; responsible primarily for accounting, treasury, finance, information resources and risk management. He previously served as Treasurer of SEI from 1986 to 1992 and Director of Corporate Finance of SCS from 1988 to 1992.
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.
(f)(4) Involvement in certain legal proceedings. None.
SAVANNAH
(a)(5) Identification of directors of SAVANNAH.
ARTHUR M. GIGNILLIAT, JR. President and Chief Executive Officer Age 61 Served as Director since 8-31-82
HELEN QUATTLEBAUM ARTLEY (1) Age 66 Served as Director since 5-17-77
PAUL J. DENICOLA (1) Age 45 Served as Director since 3-14-91
BRIAN R. FOSTER (1) Age 44 Served as Director since 5-16-89
WALTER D. GNANN (1) Age 58 Served as Director since 5-17-83
JOHN M. MCINTOSH (1) Age 69 Served as Director since 2-27-68
III-10
ROBERT B. MILLER, III (1) Age 48 Served as Director since 5-17-83
JAMES M. PIETTE (1) Age 69 Served as Director since 6-12-73
ARNOLD M. TENEBAUM (1) Age 57 Served as Director since 5-17-77
FREDERICK F. WILLIAMS, JR. (1) Age 66 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 18, 1993) 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 61 Served as Executive Officer since 2-15-72
W. MILES GREER Vice President - Marketing and Customer Services Age 50 Served as Executive Officer since 11-20-85
LARRY M. PORTER Vice President - Operations Age 49 Served as Executive Officer since 7-1-91
KIRBY R. WILLIS Vice President, Treasurer and Chief Financial Officer Age 42 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 18, 1993) for one year until the next annual meeting or until his successor is elected and qualified, except Mr. Willis.
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 1985. Director of Savannah Foods and Industries, Inc.
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 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.
III-11
JOHN M. MCINTOSH - Chairman of the Executive Committee, SAVANNAH; retired Chairman of the Board of Directors and Chief Executive Officer, SAVANNAH from 1974 to 1984. Director of SOUTHERN.
ROBERT B. MILLER, III - President of American Builders of Savannah.
JAMES M. PIETTE - Vice President - Special Projects, Union Camp Corporation, since 1989. Retired Vice Chairman, Board of Directors, Union Camp Corporation from 1987 to 1989.
ARNOLD M. TENENBAUM - President 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 January 1994. Formerly served as Vice President - Economic Development and Corporate Services from 1989 through 1993 and Vice President - Economic Development and Governmental Affairs from 1985 to 1989.
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 effective January 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.
III-12
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
(A) SUMMARY COMPENSATION TABLES. The following tables set forth information concerning the Chief Executive Officer and the four most highly compensated executive officers for each of the operating affiliates (ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH), serving as of December 31, 1993 whose total annual salary and bonus exceeded $100,000. No information is provided for any person for any year in which such person did not serve as an executive officer of the operating affiliate. The number of SOUTHERN common shares do not reflect the stock distribution resulting from the two-for-one common stock split approved by SOUTHERN's board of directors in January, 1994.
KEY TERMS used in this Item will have the following meanings:-
AME........... ABOVE-MARKET EARNINGS ON DEFERRED COMPENSATION ESP........... EMPLOYEE SAVINGS PLAN ESOP.......... EMPLOYEE STOCK OWNERSHIP PLAN SBP........... SUPPLEMENTAL BENEFIT PLAN VBP........... VEHICLE BUYOUT PROGRAM
ALABAMA
SUMMARY COMPENSATION TABLE
III-13 ALABAMA SUMMARY COMPENSATION TABLE (CONTINUED)
(1) Tax reimbursement by ALABAMA and certain personal benefits, including membership fee of $28,402 for Mr. Jones in 1992. In accordance with the transition rules of the SEC, information for 1991 is omitted. (2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods ending December 31, 1991, 1992 and 1993, respectively. (3) ALABAMA contributions to the ESP, ESOP, non-pension related accruals under the SBP (ERISA excess plan under which accruals are made to offset Internal Revenue Code imposed limitations under the Employee Savings and Stock Ownership Plans), and payments under a VBP for the following:- Name ESP ESOP SBP VBP - ---- --- ---- --- --- E. B. Harris $6,746 $1,709 $12,933 $18,000 T. J. Bowden 8,369 1,709 3,193 18,000 B. H. Farris 7,193 1,499 726 18,000 T. H. Jones 6,908 1,331 754 5,100 W. B. Hutchins, III 6,746 1,400 671 18,000 In accordance with the transition rules of the SEC, information for 1991 is omitted. (4) Effective January 31, 1994, Mr. Bowden resigned to become president of GULF.
III-14
GEORGIA SUMMARY COMPENSATION TABLE
(1) Due to the pay schedules at GEORGIA, 1992 salary reflects one additional pay period compared with 1991. (2) Tax reimbursement by GEORGIA on certain personal benefits. In accordance with the transition rules of the SEC, information for 1991 is omitted. (3) Payouts made in 1992, 1993 and 1994 for the four-year performance periods ending December 31, 1991, 1992 and 1993, respectively. (4) GEORGIA contributions to the ESP, ESOP, non-pension related accruals under the SBP (ERISA excess plan under which accruals are made to offset Internal Revenue Code imposed limitations under the Employee Savings and Stock Ownership Plans) and payments under a VBP for the following:- Name ESP ESOP SBP VBP - ---- --- ---- --- --- A. W. Dahlberg $6,746 $1,709 $18,092 $18,000 D. H. Evans 8,592 1,709 1,218 18,000 W. Y. Jobe 7,667 1,709 1,882 18,000 G. R. Hodges 7,349 1,620 3,660 18,000 K. E. Adams 7,204 1,634 1,462 18,000 In accordance with the transition rules of the SEC, information for 1991 is omitted. (5) Effective December 31, 1993, Mr. Dahlberg resigned to become president of SOUTHERN.
III-15 GULF SUMMARY COMPENSATION TABLE
(1) Tax reimbursement by GULF on certain personal benefits. In accordance with the transition rules of the SEC, information for 1991 is omitted. (2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods ending December 31, 1991, 1992 and 1993, respectively. (3) GULF contributions to the ESP, ESOP, non-pension related accruals under the SBP (ERISA excess plan under which accruals are made to offset Internal Revenue Code imposed limitations under the Employee Savings and Stock Ownership Plans) and payments under a VBP for the following:- Name ESP ESOP SBP VBP - ---- --- ---- --- --- D. L. McCrary $9,300 $1,709 $6,057 $ 2,788 G. E. Holland, Jr. 4,652 - - 16,363 E. B. Parsons, Jr 6,948 1,709 410 16,363 A. E. Scarbrough 6,746 1,338 282 16,363 J. E. Hodges, Jr. 6,651 1,313 - 16,363 In accordance with the transition rules of the SEC, information for 1991 is omitted. (4) Employee and executive officer of GULF since April 25, 1992. Not eligible to participate in the Long-Term Incentive Plan until January 1, 1993. (5) "All Other Compensation" previously reported as $4,149 for Mr. Holland in the Form 10-K for the year ended December 31, 1992, should have been $0 since Mr. Holland was not yet eligible to participate in ESP and ESOP.
III-16
MISSISSIPPI SUMMARY COMPENSATION TABLE
(1) Tax reimbursement by MISSISSIPPI on certain personal benefits. In accordance with the transition rules of the SEC, information for 1991 is omitted. (2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods ending December 31, 1991, 1992 and 1993, respectively. (3) MISSISSIPPI contributions to the ESP, ESOP, non-pension related accruals under the SBP (ERISA excess plan under which accruals are made to offset Internal Revenue Code imposed limitations under the Employee Savings and Stock Ownership Plans) and payments under a VBP for the following:- Name ESP ESOP SBP VBP - ---- --- ---- --- --- David M. Ratcliffe $7,895 $1,709 $2,774 $5,509 R. G. Dawson 6,746 1,252 - 7,045 H. E. Blakeslee 6,843 1,355 - 7,452 D. E. Mason 6,671 1,286 - 7,452 T. A. Fanning 5,520 1,019 - 8,116 In accordance with the transition rules of the SEC, information for 1991 is omitted. (4) Effective March 1, 1994, Mr. Dawson resigned to become a vice president of SEI. (5) Benefits under MISSISSIPPI's VBP for 1992 in the amounts of $13,169 and $12,425 to Messrs. Dawson and Fanning, respectively, previously reported in the Form 10-K for the year ended December 31, 1992, under the "Other Annual Compensation" column have been moved to the "All Other Compensation" column.
III-17
SAVANNAH SUMMARY COMPENSATION TABLE
(1) Tax reimbursement by SAVANNAH on certain personal benefits. In accordance with the transition rules of the SEC, information for 1991 is omitted. (2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods ending December 31, 1991, 1992 and 1993, respectively. (3) SAVANNAH contributions to the ESP, under Section 401(k) of the Internal Revenue Code, ESOP, AME and payments under a VBP for the following:- Name ESP ESOP AME VBP - ---- --- ---- --- --- A. M. Gignilliat $6,746 $3,092 $7,479 $14,195 E. O. Veale 6,163 2,359 5,702 - L. M. Porter 4,943 1,774 658 14,195 W. M. Greer 5,045 1,764 877 14,195 J. L. Rayburn 2,284 1,650 1,911 14,195 In accordance with the transition rules of the SEC, information for 1991 is omitted. (4) Retired effective December 31, 1993. (5) Not eligible for Long-term Incentive Payout until January 1, 1994. (6) Resigned effective December 31, 1993.
III-18
STOCK OPTION GRANTS IN 1993
(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, 1993. The number of SOUTHERN common shares shown and the per share exercise price and market price do not reflect the stock distribution resulting from the two-for-one common stock split approved by SOUTHERN's board of directors in January, 1994.
See next page for footnotes.
III-19
STOCK OPTION GRANTS IN 1993
(1) Grants were made on July 19, 1993, and vest 25% per year on the anniversary date of the grant. Grants fully vest upon termination incident to death, disability, or retirement. The exercise price is the average of the high and low fair market value of SOUTHERN's common stock on the date granted. In accordance with the terms of the Executive Stock Plan, Mr. Jones' unexercised options expire on April 1, 1998, three years after his normal retirement date; Mr. McCrary's unexercised options expire on May 1, 1997, three years after his normal retirement date; and Mr. Gignilliat's unexercised options expire on September 3, 2000, three years after his normal retirement date. (2) A total of 179,746 stock options were granted in 1993 to key executives participating in SOUTHERN's Executive Stock Plan. (3) Based on the Black-Scholes option valuation model. The actual value, if any, an executive officer may realize ultimately depends on the market value of SOUTHERN's common stock at a future date. This valuation is provided pursuant to SEC disclosure rules and there is no assurance that the value realized will be at or near the value estimated by the Black-Scholes model. Assumptions used to calculate this value: price volatility - 12.45%; risk-free rate of return - 5.81%; dividend yield - 5.37%; and time to exercise - ten years.
III-20
AGGREGATED STOCK OPTION EXERCISES IN 1993 AND YEAR-END OPTION VALUES
(C) AGGREGATED STOCK OPTION EXERCISES. The following table sets forth information concerning options exercised during the year ending December 31, 1993, by the named executive officers and the value of unexercised options held by them as of December 31, 1993. The number of SOUTHERN common shares shown and the per share exercise price and market price do not reflect the stock distribution resulting from the two-for-one common stock split approved by SOUTHERN's board of directors in January, 1994.
See next page for footnotes.
III-21
AGGREGATED STOCK OPTION EXERCISES IN 1993 AND YEAR-END OPTION VALUES
(1) This represents the excess of the fair market value of SOUTHERN's common stock of $44.125 per share, as of December 31, 1993, above the exercise price of the options. One column reports the "value" of options that are vested and therefore could be exercised; the other "value" of options that are not vested and therefore could not be exercised as of December 31, 1993. (2) The "Value Realized" is ordinary income, before taxes, and represents the amount equal to the excess of the fair market value of the shares at the time of exercise over the exercise price.
III-22
LONG-TERM INCENTIVE PLANS - AWARDS IN 1993
(D) LONG-TERM INCENTIVE PLANS. The following table sets forth the long-term incentive plan awards made to the named executive officers for the performance period January 1, 1993 through December 31, 1996.
See next page for footnotes.
III-23
LONG-TERM INCENTIVE PLANS - AWARDS IN 1993
III-24
PENSION PLAN TABLE
(e)(1) The following table sets forth the estimated combined annual pension benefits under the pension and supplemental defined benefit plans in effect during 1993 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, 1993, the applicable compensation levels and years of accredited service are presented in the following tables:
III-25
SAVANNAH has in effect a qualified, trusteed, noncontributory, defined benefit pension plan which provides pension benefits to employees upon retirement at the normal retirement age after designated periods of accredited service and at a specified compensation level. The plan provides pension benefits under a formula which includes each participant's years of service with the Southern system and average annual earnings of the highest three of the final 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 1993 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 Mr. Holland pursuant to a supplemental pension agreement.
III-26
As of December 31, 1993, the applicable compensation levels and years of accredited service is 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
(1) The plan benefits are subject to the maximum benefit limitations set forth in Section 415 of the Internal Revenue Code.
III-27
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.
(f) COMPENSATION OF DIRECTORS.
(1) Standard Arrangements. The following table presents compensation paid to the directors, during 1993 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, 1993 in addition to or in lieu of that specified by the standard arrangements specified above.
(1) Committee Chairmen receive an additional $500 per year fee. (2) Established for period September 15, 1993 through May 31, 1994. (3) Chairman of Executive Committee receives an additional $3,000 per month fee.
III-28
(g) EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE IN CONTROL ARRANGEMENTS.
None.
(h) REPORT ON REPRICING OF OPTIONS.
None.
(i) ADDITIONAL INFORMATION WITH RESPECT TO COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION IN COMPENSATION DECISION.
ALABAMA
Elmer B. Harris serves on the Compensation Committee of AmSouth Bancorporation. John W. Woods, a director of ALABAMA is an executive officer of AmSouth Bancorporation.
GULF
Messrs. Paul J. DeNicola and Douglas L. McCrary are ex officio members of its Compensation Committee.
III-29
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, 1993. 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, 1993. The number of SOUTHERN common shares shown do not reflect the stock distribution resulting from the two-for-one common stock split approved by SOUTHERN'S board of directors in January, 1994.
III-30
III-31
III-32
III-33
(1) As used in this table, "beneficial ownership" means the sole or shared power to vote, or to direct the voting of, a security and/or investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security). (2) The shares shown include shares of common stock of which certain directors and executive officers have the right to acquire beneficial ownership within 60 days pursuant to the Executive Stock Plan, as follows: Mr. Addison, 86,357 shares; Mr. Blakeslee, 660 shares; Mr. Bowden, 5,763 shares; Mr. Dahlberg, 4,278 shares; Mr. Farris, 863 shares; Mr. Gignilliat, 8,556 shares; Mr. Guthrie 15,720 shares; Mr. Harris, 14,215 shares; Mr. Haubein, 835 shares; Mr. Hodges, 5,429 shares; Mr. Holland, 698 shares; Mr. Hutchins, 706 shares; Mr. Jones, 848 shares; Mr. Klappa, 671 shares, Mr. C. D. McCrary, 691 shares; Mr. D. L. McCrary, 9,668 shares; and Mr. Ratcliffe, 5,643 shares. Also included are shares of SOUTHERN common stock held by the spouses of the following directors: Mr. Addison, 670 shares; Mr. Copenhaver, 350 shares; Mr. Harris, 155 shares; Mr. Parker, 22 shares; and Dr. Shatto, 5,067 shares.
III-34
(C) CHANGES IN CONTROL. The operating affiliates know of no arrangements which may at a subsequent date result in any change in control.
GEORGIA'S Mr. Russell failed to file on a timely basis a single report disclosing one transaction on Form 4 as required by Section 16 of the Securities Exchange Act of 1934.
MISSISSIPPI'S Messrs. McLean, Jr., Hurt and Seal, Jr. each failed to file on a timely basis a single report disclosing one transaction on Form 4 as required by Section 16 of the Securities Exchange Act of 1934.
SAVANNAH'S Mr. Gnann failed to file on a timely basis a single report disclosing one transaction on Form 4 as required by Section 16 of the Securities Exchange Act of 1934.
MR. DENICOLA, a director of GULF, MISSISSIPPI and SAVANNAH, failed to file on a timely basis a single report, disclosing one transaction on Form 4 as required by Section 16 of the Securities Exchange Act of 1934.
III-35
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ALABAMA
(a) Transactions with management and others.
During 1993, ALABAMA, in the ordinary course of business, paid premiums amounting to approximately $400,000 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 serves as Chairman.
The firm of Inzer, Stivender, Haney & Johnson, P.A., performed certain legal services for ALABAMA during 1993. Mr. James C. Inzer, Jr., partner in this firm, is also a director of ALABAMA.
ALABAMA purchased automobiles and parts in the amount of approximately $200,000 from companies in which Mr. Blount, a director of ALABAMA, owns 85% interests.
ALABAMA purchased electrical supplies in the amount of approximately $200,000 from L & K Electric Supply Company, Ltd. during 1993. Mr. Willie, director of ALABAMA and SOUTHERN, owns an interest in and serves as president of this firm.
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.
In 1993, GEORGIA was indebted in a maximum amount of $105 million to Wachovia Bank and its affiliates, of which G. Joseph Prendergast serves as President and Chief Executive Officer of Wachovia Corporation of Georgia and Wachovia Bank of Georgia, N.A.
In 1993, GEORGIA was indebted in a maximum amount of $285 million to NationsBank and its affiliates of which Mr. James R. Lientz, Jr. serves as President of NationsBank of Georgia.
(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 $800,000 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) Certain business relationships.
During 1993, MISSISSIPPI was indebted in a maximum amount of $12.4 million to Hancock Bank, of which Leo W. Seal, Jr. serves as Chairman of the Board and Chief Executive Officer.
(b) Certain business relationships. None.
(c) Indebtedness of management. None.
III-36
(d) Transactions with promoters. None.
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 1993, 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.
(c) Indebtedness of management. None.
(d) Transactions with promoters. None.
III-37 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 1993 the registrants filed Current Reports on Form 8-K as follows:
ALABAMA filed Forms 8-K dated October 27, 1993, and November 16, 1993, to facilitate security sales.
GEORGIA filed a Form 8-K dated October 20, 1993, to facilitate a security sale.
GULF filed a Form 8-K dated November 3, 1993, to facilitate a security sale.
SAVANNAH filed a Form 8-K dated November 9, 1993, 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 Edward L. Addison, Chairman
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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.
Edward L. Addison Chairman of the Board (Principal Executive Officer)
W. L. Westbrook Financial Vice President (Principal Financial and Accounting Officer)
Directors:
W. P. Copenhaver John M. McIntosh. A. W. Dahlberg Earl D. McLean, Jr. Paul J. DeNicola William A. Parker Jack Edwards William J. Rushton, III H. Allen Franklin Gloria M. Shatto L. G. Hardman, III Herbert Stockham Elmer B. Harris Louis J. Willie
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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)
Charles D. McCrary Senior Vice President (Principal Financial Officer)
David L. Whitson Vice President and Comptroller (Principal Accounting Officer)
Directors:
Edward L. Addison William V. Muse Whit Armstrong John T. Porter Philip E. Austin Gerald H. Powell Margaret A. Carpenter 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. Louis J. Willie Wallace D. Malone, Jr. John W. Woods
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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: Edward L. Addison G. Joseph Prendergast Bennett A. Brown Herman J. Russell William P. Copenhaver Gloria M. Shatto A. W. Dahlberg Robert Strickland William A. Fickling, Jr. William Jerry Vereen L. G. Hardman, III Thomas R. Williams James R. Lientz, Jr.
By Wayne Boston (Wayne Boston, Attorney-in-fact) Date: March 25, 1994
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 D. L. McCrary, Chairman of the Board
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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.
D. L. McCrary Chairman of the Board and Chief Executive Officer (Principal Executive Officer)
A. E. Scarbrough Vice President - Finance (Principal Financial and Accounting Officer)
Directors: Reed Bell Travis J. Bowden Paul J. DeNicola Fred C. Donovan W. D. Hull, Jr. C. W. Ruckel J. K. Tannehill
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25,1994
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
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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)
Thomas A. Fanning Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Paul J. DeNicola Edwin E. Downer Robert S. Gaddis Walter H. Hurt, III Aubrey K. Lucas Earl D. McLean, Jr. Gerald J. St. Pe' Leo W. Seal, Jr. N. Eugene Warr
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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 Paul J. DeNicola Brian R. Foster Walter D. Gnann John M. McIntosh Robert B. Miller, III James M. Piette Arnold M. Tenenbaum Frederick F. Williams, Jr.
By Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
IV-4
EXHIBIT 21. SUBSIDIARIES OF THE REGISTRANTS.
(1) Owned by Alabama Power Company. (2) Owned by Georgia Power Company. (3) Owned by SEI Holdings, Inc. (4) 94% owned jointly by Asociados de Electricidad, S. A. (14%) and SEI Holdings, Inc. (80%) (5) 59% owned by SEI y Asociados de Argentina, S. A. (6) Owned by SEI Holdings III, Inc. (7) 36% owned by SEI Chile, S. A. (8) Owned by SEI Holdings IV, Inc. (9) Owned jointly by Inversores de Electricidad, S. A. (15%) and SEI Bahamas Argentina I, Inc. (85%) (10) Owned by Southern Electric Bahamas Holdings, Ltd. (11) 50% owned by Southern Electric Bahamas, Ltd. (12) Owned equally by Alabama Power Company and Georgia Power Company. (13) Owned by Southern Electric International, Inc. (14) Owned by Southern Electric Wholesale Generators, Inc.
IV-5 ARTHUR ANDERSEN & CO.
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 16, 1994 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 and 33-51433.
/s/ Arthur Andersen & Co.
Atlanta, Georgia March 25, 1994
IV-6 ARTHUR ANDERSEN & CO.
Exhibit 23(b)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 16, 1994 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 & Co.
Birmingham, Alabama March 25, 1994
IV-7 ARTHUR ANDERSEN & CO.
Exhibit 23(c)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 16, 1994 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 & Co.
Atlanta, Georgia March 25, 1994
IV-8 ARTHUR ANDERSEN & CO.
Exhibit 23(d)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 16, 1994 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 & Co.
Atlanta, Georgia March 25, 1994
IV-9 ARTHUR ANDERSEN & CO.
Exhibit 23(e)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 16, 1994 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 & Co.
Atlanta, Georgia March 25, 1994
IV-10 ARTHUR ANDERSEN & CO.
Exhibit 23(f)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 16, 1994 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 & Co.
Atlanta, Georgia March 25, 1994
IV-11 ARTHUR ANDERSEN & CO.
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 16, 1994. 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 and S-3, S-11 through S-14, S-35 through S-37, S-53, and S-59) 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 & Co.
Atlanta, Georgia February 16, 1994
IV-12 ARTHUR ANDERSEN & CO.
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 16, 1994. 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-4, S-15 through S-18, S-38 through S-40, S-54, and S-60) 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 & Co.
Birmingham, Alabama February 16, 1994
IV-13 ARTHUR ANDERSEN & CO.
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 16, 1994. 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-5, S-19 through S-22, S-41 through S-43, S-55, and S-61) 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 & Co.
Atlanta, Georgia February 16, 1994
IV-14 ARTHUR ANDERSEN & CO.
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 16, 1994. 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-6, S-23 through S-26, S-44 through S-46, S-56, and S-62) 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 & Co.
Atlanta, Georgia February 16, 1994
IV-15 ARTHUR ANDERSEN & CO.
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 16, 1994. 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-7 and S-8, S-27 through S-30, S-47 through S-49, S-57, and S-63) 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 & Co.
Atlanta, Georgia February 16, 1994
IV-16 ARTHUR ANDERSEN & CO.
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 16, 1994. 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-9 and S-10, S-31 through S-34, S-50 through S-52, S-58, and S-64) 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 & Co.
Atlanta, Georgia February 16, 1994
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedules I through XIV not listed above are omitted as not applicable or not required. Columns omitted from schedules filed have been omitted because the information is not applicable or not required.
S-1
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES (STATED IN THOUSANDS OF DOLLARS)
See Summary of Transactions and Notes on Page S-3
S-2
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES (STATED IN THOUSANDS OF DOLLARS)
Total additions and total retirements for 1991, 1992 and 1993, as summarized below, were each less than 10% of the total balances as of the respective year-ends. Retirements include non-depreciable plant retirements and unamortized portions of retirements to acquisition adjustments. There were no additions to individual accounts in excess of two percent of total assets other than transfers from Construction Work in Progress.
(NOTE 1) OTHER CHANGES INCLUDE THE FOLLOWING (STATED IN THOUSANDS OF DOLLARS)
S-3
ALABAMA POWER COMPANY SCHEDULE V -- UTILITY PLANT, INCLUDING INTANGIBLES (STATED IN THOUSANDS OF DOLLARS)
Total additions and total retirements for 1991, 1992 and 1993, as summarized below, were each less than 10% of the total balances as of the respective year-ends. Retirements below include non-depreciable plant retirements. There were no additions to individual accounts in excess of two percent of total assets other than transfers from Construction Work in Progress. Other changes include a reduction to utility plant of $61,960,000 for the partial sale of Miller Steam Plant in 1992.
S-4
GEORGIA POWER COMPANY SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES (STATED IN THOUSANDS OF DOLLARS)
Total additions and total retirements for 1991, 1992 and 1993, as summarized below, were each less than 10% of the total balances as of the respective year-ends. Retirements include non-depreciable plant retirements and unamortized portions of Plant Scherer acquisition adjustment retired for sales in 1991 and 1993. There were no additions to individual accounts in excess of two percent of total assets other than transfers from Construction Work in Progress. Other changes for 1993, include an increase to plant of $46,473,000 for the taxes applicable to capitalized AFUDC debt.
S-5
GULF POWER COMPANY SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES (STATED IN THOUSANDS OF DOLLARS)
Total additions and total retirements for 1991, 1992 and 1993, as summarized below, were each less than 10% of the total balances as of the respective year-ends. There were no additions to individual accounts in excess of two percent of total assets other than transfers from Construction Work in Progress.
S-6
MISSISSIPPI POWER COMPANY SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES (STATED IN THOUSANDS OF DOLLARS)
Total additions and total retirements for 1991 and 1992, as summarized below, were each less than 10% of the total balances as of the respective year-ends. Additions for 1993 were greater than 10% of the year-end balance and, consequently, 1993 is reported in full detail on page S-8. There were no additions to individual accounts in excess of two percent of total assets other than transfers from Construction Work in Progress.
S-7
MISSISSIPPI POWER COMPANY SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES FOR THE YEAR ENDED DECEMBER 31,1993 (STATED IN THOUSANDS OF DOLLARS)
S-8
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES (STATED IN THOUSANDS OF DOLLARS)
Total additions and total retirements for 1991 and 1992, as summarized below, were each less than 10% of the total balances as of the respective year-ends. Additions for 1993 were greater than 10% of the year-end balance and, consequently, 1993 is reported in full detail on page S-10. There were no additions to individual accounts in excess of two percent of total assets other than transfers from Construction Work in Progress.
S-9
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES FOR THE YEAR ENDED DECEMBER 31, 1993 (STATED IN THOUSANDS OF DOLLARS)
S-10
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1993 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-14
S-11
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1992 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-14
S-12
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1991 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-14
S-13
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES NOTES TO SCHEDULE VI -ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991 (STATED IN THOUSANDS OF DOLLARS)
S-14
ALABAMA POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1993 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-18
S-15
ALABAMA POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1992 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-18
S-16
ALABAMA POWER COMPANY SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1991 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-18
S-17
ALABAMA POWER COMPANY NOTES TO SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991 (STATED IN THOUSANDS OF DOLLARS)
S-18
GEORGIA POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1993 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-22
S-19
GEORGIA POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1992 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-22
S-20
GEORGIA POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1991 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-22 S-21
GEORGIA POWER COMPANY NOTES TO SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991 (STATED IN THOUSANDS OF DOLLARS)
S-22
GULF POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1993 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-26
S-23
GULF POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1992 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-26 S-24
GULF POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1991 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-26
S-25
GULF POWER COMPANY NOTES TO SCHEDULE VI -ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991 (STATED IN THOUSANDS OF DOLLARS)
S-26
MISSISSIPPI POWER COMPANY SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1993 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-30
S-27
MISSISSIPPI POWER COMPANY SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1992 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-30
S-28
MISSISSIPPI POWER COMPANY SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1991 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-30
S-29
MISSISSIPPI POWER COMPANY NOTES TO SCHEDULE VI -ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PL FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991 (STATED IN THOUSANDS OF DOLLARS)
S-30
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1993 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-34
S-31
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1992 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-34
S-32
SAVANNAH ELECTRIC AND POWER COMPANY SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEAR ENDED DECEMBER 31, 1991 (STATED IN THOUSANDS OF DOLLARS)
See Notes on Page S-34
S-33
SAVANNAH ELECTRIC AND POWER COMPANY NOTES TO SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991 (STATED IN THOUSANDS OF DOLLARS)
S-34
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
- ------------------------- Notes: (1) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (2) Insurance recoveries net of charges to reserve for purposes for which reserve was created. (3) See Note 1 to SOUTHERN's financial statements under "Nuclear Decommissioning" in Item 8 herein for further information. (4) Represents additional funding to reserve. (5) See Note 1 to SOUTHERN's financial statements under "Revenues and Fuel Costs" in Item 8 herein for further information.
S-35
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
- ----------------------------- Notes: (1) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (2) See Note 1 to SOUTHERN's financial statements under "Depreciation and Nuclear Decommissioning" in Item 8 herein for further information. (3) See Note 1 to SOUTHERN's financial statements under "Revenues and Fuel Costs" in Item 8 herein for further information. (4) Capitalized.
S-36 THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VIII--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
- ------------------ Notes: (1) See Note 8 to SOUTHERN's financial statements in Item 8 herein for a description of the Gulf States settlement. (2) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (3) Insurance recoveries net of charges to reserve for purposes for which reserve was created. (4) See Note 1 to SOUTHERN's financial statements under "Depreciation and Nuclear Decommissioning" in Item 8 herein for further information.
S-37 ALABAMA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
- ------------------ Notes: (1) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (2) See Note 1 to ALABAMA's financial statements under "Depreciation and Nuclear Decommissioning" in Item 8 herein for further information. (3) Represents additional funding to reserve. (4) See Note 1 to ALABAMA's financial statements under "Revenues and Fuel Costs" in Item 8 herein for further information.
S-38 ALABAMA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
- ----------------------------- Notes: (1) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (2) See Note 1 to ALABAMA's financial statements under "Depreciation and Nuclear Decommissioning" in Item 8 herein for further information. (3) See Note 1 to ALABAMA's financial statements under "Revenues and Fuel Costs" in Item 8 herein for further Information.
S-39 ALABAMA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
- ----------------------- Notes: (1) See Note 7 to the financial statements in Item 8 herein for a description of the Gulf States settlement. The provision for uncollectible was reversed. (2) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (3) See Note 1 to ALABAMA's financial statements under "Depreciation and Nuclear Decommissioning" in Item 8 herein for further information.
S-40 GEORGIA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
- -------------------- Notes: (1) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (2) See Note 1 to GEORGIA's financial statements under "Nuclear Decommissioning" in Item 8 herein for further information. (3) Represents additional funding to reserve. (4) See Note 1 to GEORGIA's financial statements under "Revenues and Fuel Costs" in Item 8 herein for further information.
S-41 GEORGIA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
- ----------------------- Notes: (1) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (2) See Note 1 to GEORGIA's financial statements under "Nuclear Decommissioning" in Item 8 herein for further information. (3) See Note 1 to GEORGIA's financial statements under "Revenues and Fuel Costs" in Item 8 herein for further information.
S-42 GEORGIA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
- ------------------ Note: (1) See Note 3 to GEORGIA's financial statements in Item 8 herein for a description of the Gulf States settlement. The provision for uncollectible accounts was reversed. (2) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (3) See Note 1 to GEORGIA's financial statements under "Nuclear Decommissioning" in Item 8 herein for further information.
S-43 GULF POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
- --------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-44 GULF POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
- -------------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-45 GULF POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
- ------------------ Notes: (1) See Note 7 to GULF's financial statements in Item 8 herein for a description of the Gulf States settlement. The provision for uncollectible was reversed. (2) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-46 MISSISSIPPI POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
- --------------- Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-47 MISSISSIPPI POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
- ------------------ Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-48 MISSISSIPPI POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in thousands of Dollars)
- ----------------- Notes: (1) See Note 7 to MISSISSIPPI's financial statements in Item 8 herein for a description of the Gulf States settlement. The provision for uncollectible was reversed. (2) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-49 SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
- -------------------------- Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.
S-50 SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
- ---------------------- Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.
S-51 SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.
S-52 THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE IX - SHORT-TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
- ---------------------- Notes: (1) At month-end. (2) Average based on daily borrowings during period (averages and rates quoted on an actual day year basis). (3) This note payable is an obligation of SEI and does not include borrowings from SOUTHERN. (4) See Note 5 to SOUTHERN's financial statements in Item 8 herein for details regarding SOUTHERN's and its subsidiaries lines of credit and general terms of commitment agreements.
S-53 ALABAMA POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992, 1991
(Stated in Thousands of Dollars)
- ----------------- Notes: (1) At month-end. (2) Average based on daily borrowings during the period (averages and rates quoted on an actual day year basis). (3) ALABAMA also issued commercial paper during 1993, although none was outstanding at year-end. The data shown reflects the issuance of commercial paper. (4) See Note 5 to ALABAMA's financial statements in Item 8 herein for details regarding ALABAMA's lines of credit.
S-54 GEORGIA POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
- -------------------- Notes: (1) At month-end (2) Average based on daily borrowings during period (averages and rates quoted on an actual day year basis). (3) See Note 8 to GEORGIA's financial statements in Item 8 herein for details regarding GEORGIA's lines of credit and general terms of its commitment agreements.
S-55 GULF POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
- ---------------------- Notes: (1) At month-end (2) Average based on daily borrowings during period (averages and rates quoted on an actual day year basis). (3) See Note 5 to GULF's financial statements in Item 8 herein for a description of this short-term indebtedness. (4) See Note 5 to GULF's financial statements in Item 8 herein for details regarding GULF's lines of credit and general terms of its commitment agreements.
S-56 MISSISSIPPI POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
- ---------------------- Notes: (1) At month-end (2) Average based on daily borrowings during period (averages and rates quoted on an actual day year basis). (3) See Note 5 to MISSISSIPPI's financial statements in Item 8 herein for details regarding MISSISSIPPI's lines of credit and general terms of its commitment agreements.
S-57 SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
Notes: (1) At month-end (2) Average based on daily borrowings during period (averages and rates quoted on an actual day year basis). (3) See Note 5 to SAVANNAH's financial statements in Item 8 herein for details regarding SAVANNAH's lines of credit and general terms of its commitment agreements.
S-58 THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
S-59 ALABAMA POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
S-60 GEORGIA POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
S-61 GULF POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
S-62 MISSISSIPPI POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
S-63 SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
S-64 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 to date. (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 November 19, 1993. (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) and in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a).)
(b) 2 - By-laws of ALABAMA as amended effective April 24, 1992, and as presently in effect. (Designated in Registration No. 33-48885 as Exhibit 4(c).)
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).)
E-1 (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.
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.
(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 January 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
E-2 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) and in Certificate of Notification, File No. 70-8069, as Exhibits A and B.)
GEORGIA
(d) - 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 January 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 and in Certificate of Notification, File No. 70-7832, as Exhibit C.)
GULF
(e) - Indenture dated as of September 1, 1941, between GULF and The Chase Manhattan Bank (National Association) and The Citizens & Peoples National Bank of Pensacola, as Trustees, and indentures supplemental thereto through
E-3 November 1, 1993. (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 and in Certificate of Notification, File No. 70-8229, as Exhibit A.)
MISSISSIPPI
(f) - Indenture dated as of September 1, 1941, between MISSISSIPPI and Morgan Guaranty Trust Company of New York, as Trustee, and indentures supplemental thereto through November 1, 1993. (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 and in Certificate of Notification, File No. 70-8127, as Exhibit A.)
SAVANNAH
(g) - 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).)
E-4 (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).)
(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).)
E-5 (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).)
(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 and Amendment No. 3 dated as of August 1, 1988, 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
E-6 No. 1-3526, as Exhibit 10(o)(2) and in SOUTHERN's Form 10-K for the year ended December 31, 1989, File No. 1-3526, as Exhibit 10(n)(2).)
(a) 25 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980 and Amendment No. 1 dated as of December 3, 1985, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-4 and in SOUTHERN's Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(4).)
(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.)
(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
E-7 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).)
(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).)
E-8 (a) 43 - Purchase and Ownership Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-1.)
(a) 44 - Operating Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-2.)
(a) 45 - Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Gulf States and MISSISSIPPI. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1981, File No. 0-6849, as Exhibit 10(f), in MISSISSIPPI's Form 10-K for the year ended December 31, 1982, File No. 0-6849, as Exhibit 10(f)(2) and in MISSISSIPPI's Form 10-K for the year ended December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).)
(a) 46 - Form of commitment agreement, Amendment No. 1 and Amendment No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and MISSISSIPPI revolving credits. (Designated in Form U-1, File No. 70-7738, as Exhibit A-5 and in Form U-1, File No. 70-7937, as A-5(b).)
(a) 47 - Block Power Sale Agreement between GEORGIA and OPC dated as of November 12, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(cc).)
(a) 48 - Coordination Services Agreement between GEORGIA and OPC dated as of November 12, 1990. (Designated in GEORGIA's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(dd).)
*(a) 49 - Amended and Restated Nuclear Managing Board Agreement for Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and Dalton dated as of July 1, 1993.
(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).)
E-9 (a) 53 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1992, File No. 1-3526, as Exhibit 10(a)53.)
*(a) 54 - Amendment No. 4 to the Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of December 31, 1990.
*(a) 55 - Amendment No. 2 to the Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of December 31, 1990.
*(a) 56 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and JEA.
*(a) 57 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992.
*(a) 58 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992.
*(a) 59 - Power Purchase Agreement dated as of December 3, 1993 between GEORGIA and FPC.
ALABAMA
(b) 1 - Indenture dated as of June 1, 1959, between SEGCO and Citibank, N.A., as Trustee, and indentures supplemental thereto through December 1, 1962. (Designated in Registration No. 2-59843 as Exhibit 2(a)-8.)
(b) 2 - 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) 3 - 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) 4 - 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) 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.
E-10 (b) 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.
(b) 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.
(b) 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.
(b) 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.
(b) 10 - 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) 11 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(b) 12 - 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) 13 - Firm Power Purchase Contract between ALABAMA and AMEA. (Designated in Certificate of Notification, File No. 70-7212, as Exhibit B.)
(b) 14 - 1991 Firm Power Purchase Contract between ALABAMA and AMEA. (Designated in Form U-1, File No. 70- 7873, as Exhibit B-1.)
(b) 15 - 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) 16 - 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) 17 - 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-11 (b) 18 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit 10(a)53 herein.
GEORGIA
(c) 1 - Indenture dated as of June 1, 1959, between SEGCO and Citibank, N.A., as Trustee, and indentures supplemental thereto through December 1, 1962. See Exhibit 10(b)1 herein.
(c) 2 - Service contracts dated as of January 1, 1984 and Amendment No. 1 dated as of September 6, 1985, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIP PI, SEGCO and SOUTHERN. See Exhibit 10(a)1 herein.
(c) 3 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 herein.
(c) 4 - 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) 5 - Joint Committee Agreement dated as of August 27, 1976, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)7 herein.
(c) 6 - 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) 7 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between GEORGIA and OPC. See Exhibit 10(a)9 herein.
(c) 8 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between GEORGIA and OPC. See Exhibit 10(a)10 herein.
(c) 9 - 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) 10 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between GEORGIA and OPC. See Exhibit 10(a)12 herein.
(c) 11 - 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) 12 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between GEORGIA, MEAG and Dalton. See Exhibit 10(a)14 herein.
E-12 (c) 13 - 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) 14 - 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) 15 - 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) 16 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)18 herein.
(c) 17 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)19 herein.
(c) 18 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and Dalton. See Exhibit 10(a)20 herein.
(c) 19 - Integrated Transmission System Agreement dated as of August 27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)21 herein.
(c) 20 - 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) 21 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)23 herein.
(c) 22 - 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 and Amendment No. 3 dated as of August 1, 1988, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)24 herein.
(c) 23 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980 and Amendment No. 1 dated as of December 3, 1985, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)25 herein.
(c) 24 - 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) 25 - Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between GEORGIA and Dalton. See Exhibit 10(a)27 herein.
E-13 (c) 26 - 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) 27 - 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) 28 - 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) 29 - 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.
(c) 30 - 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) 31 - 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) 32 - 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) 33 - 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) 34 - 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) 35 - 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) 36 - Power Purchase Agreement dated as of December 3, 1993 between GEORGIA and FPC. See Exhibit 10(a) 59 herein.
(c) 37 - Transition Energy Agreement dated December 31, 1990, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a) 39 herein.
E-14 (c) 38 - 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) 39 - Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18, 1988, between OPC and GEORGIA. See Exhibit 10(a)41 herein.
(c) 40 - Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between OPC and GEORGIA. See Exhibit 10(a)42 herein.
(c) 41 - Form of commitment agreement, Amendment No. 1 and Amendment No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and MISSISSIPPI revolving credits. See Exhibit 10(a)46 herein.
(c) 42 - Block Power Sale Agreement between GEORGIA and OPC dated as of November 12, 1990. See Exhibit 10(a)47 herein.
(c) 43 - Coordination Services Agreement between GEORGIA and OPC dated as of November 12, 1990. See Exhibit 10(a)48 herein.
*(c) 44 - 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) 45 - 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) 46 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and Dalton dated as of December 7, 1990. See Exhibit 10(a)51 herein.
(c) 47 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December 7, 1990. See Exhibit 10(a)52 herein.
*(c) 48 - Amendment No. 4 to the Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of December 31, 1990. See Exhibit 10(a)54 herein.
*(a) 49 - Amendment No. 2 to the Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of December 31, 1990. See Exhibit 10(a)55 herein.
*(c) 50 - 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)56 herein.
E-15 *(c) 51 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)57 herein.
*(c) 52 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)58 herein.
GULF
(d) 1 - Service contracts dated as of January 1, 1984 and Amendment No. 1 dated as of September 6, 1985, between SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN. See Exhibit 10(a)1 herein.
(d) 2 - Interchange contract dated October 28, 1988, effective January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)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.
E-16 (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.
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.
(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-17 (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.
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.
E-18 (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) 57 herein.
*(f) 10 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated December 15, 1992. See Exhibit 10(a)58 herein.
(21) *SUBSIDIARIES OF REGISTRANTS - Contained herein at page IV-5.
(23) CONSENTS OF EXPERTS AND COUNSEL
SOUTHERN
*(a) - The consent of Arthur Andersen & Co. is contained herein at page IV-6.
ALABAMA
*(b) - The consent of Arthur Andersen & Co. is contained herein at page IV-7.
GEORGIA
*(c) - The consent of Arthur Andersen & Co. is contained herein at page IV-8.
GULF
*(d) - The consent of Arthur Andersen & Co. is contained herein at page IV-9.
MISSISSIPPI
*(e) - The consent of Arthur Andersen & Co. is contained herein at page IV-10.
SAVANNAH
*(f) - The consent of Arthur Andersen & Co. is contained herein at page IV-11.
E-19 (24) POWERS OF ATTORNEY AND RESOLUTIONS
SOUTHERN
*(a) - Power of Attorney and resolution.
ALABAMA
*(b) - Power of Attorney and resolution.
GEORGIA
*(c) - Power of Attorney and resolution.
GULF
*(d) - Power of Attorney and resolution.
MISSISSIPPI
*(e) - Power of Attorney and resolution.
SAVANNAH
*(f) - Power of Attorney and resolution.
E-20