ITEM 1. BUSINESS.
General
Incorporated July 2, 1913, Louisville Gas and Electric Company (the Company) is an operating public utility that supplies natural gas to approximately 266,000 customers and electricity to approximately 341,000 customers in Louisville and adjacent areas in Kentucky. The Company's service area covers approximately 700 square miles in 17 counties and has an estimated population of 800,000. Included in this area is the Fort Knox Military Reservation, to which the Company provides both gas and electric service, but which maintains its own distribution systems. The Company also provides gas service in limited additional areas. The Company's coal-fired electric generating plants, which are all equipped with systems to remove sulfur dioxide, produce most of the Company's electricity; the remainder is generated by a hydroelectric power plant and combustion turbines. Underground gas storage fields help the Company provide economical and reliable gas service to customers.
In August 1990, the Company and LG&E Energy Corp. (Energy Corp.) implemented a corporate reorganization pursuant to a mandatory share exchange whereby each share of outstanding common stock of the Company was exchanged on a share-for-share basis for the common stock of Energy Corp. The reorganization created a corporate structure that gives the holding company the flexibility to take advantage of opportunities to expand into other businesses while insulating the Company's utility customers and senior security holders from any risks associated with such businesses. The Company's preferred stock and first mortgage bonds were not exchanged and remained securities of the Company.
The Company's Trimble County Unit 1 (Trimble County or the Unit), a 495-megawatt, coal-fired electric generating unit, which the Company began constructing in 1979, was placed in commercial operation on December 23, 1990. The Unit has been subject to numerous reviews by the Public Service Commission of Kentucky (Kentucky Commission or Commission). In July 1988, the Kentucky Commission issued an order stating that 25% of the total cost of the Unit would not be allowed for ratemaking purposes. The Company has sold a 25% ownership interest in the Unit. For a more detailed discussion of the proceedings relating to Trimble County Unit 1 and the sale of 25% of the Unit, see Electric Operations and Notes 11 and 12 of Notes to Financial Statements under Item 8.
The Clean Air Act Amendments of 1990 impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric generating plants. The Company is closely monitoring the continuing rule-making process in order to assess the precise impact of the legislation on the Company. All of the Company's coal fired boilers are equipped with sulfur dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates required by the year 2000 under the legislation. However, as part of its ongoing capital construction program, the Company has spent $10 million to date and anticipates incurring capital expenditures of approximately $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the legislation on the Company is expected to be minimal. The Company is well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities. For a more detailed discussion of the Clean Air Act and other
environmental issues, see Environmental Matters under this Item, Item 3, Item 7, and Note 10 of the Notes to Financial Statements under Item 8.
Competition among energy suppliers is increasing. In particular, competition for off-system sales, which is based primarily on price and availability of energy, has become much more intense in recent years. The addition of electric generating capacity by other utilities in the Midwest has reduced the opportunities for the Company to make interchange sales and has heightened price competition for such sales. However, such additional capacity has made lower cost power available for purchase by the Company which, in certain instances, is at a cost lower than the variable cost of generating power from the generating stations owned by the Company. In addition, the 1992 Energy Policy Act provides utilities a wider choice of sources for their electrical supply than previously available. The Act also creates generating supply options that did not exist under previous legislation and is expected to increase competition for wholesale electric sales. See Energy Policy Act of 1992 under Item 7 for a further discussion.
The Company has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; a write-off of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee involvement and training; and a major realignment and formation of new business units.
Effective January 1, 1994, Energy Corp. realigned its business to reflect its outlook for rapidly emerging competition in all segments of the energy services industry. Under the realignment, a national business unit, LG&E Energy Services was formed to develop and manage all of its utility and non-utility electric power generation and concentrate on the marketing and brokering of wholesale electric power on a regional and national basis. The realignment has allowed the Company to increase its focus on customer service and develop more customer options as the utility industry becomes more competitive. As part of the business realignment, a new subsidiary was formed to market power throughout the United States. LG&E Power Marketing Inc. (LPM), an indirect wholly owned subsidiary of Energy Corp., was among the first utility-affiliated marketers in the country to secure Federal Energy Regulatory Commission (FERC) approval to sell power at market-based rates and engage in wholesale power marketing activities. The realignment does not affect Energy Corp.'s legal structure, regulation of the Company by the Kentucky Commission or Energy Corp.'s status as an exempt holding company.
The Company envisions an open electricity transmission system that facilitates delivery of competitively priced power to all customers in the region. Toward that vision, the Company filed tariffs with FERC in 1994 which would provide transmission service to wholesale customers at rates, terms, and conditions which are comparable to those which the Company applies to itself. This comparable transmission service is a key feature of a more competitive electric utility industry.
As part of its efforts to retain existing customers and expand to new customers, in 1994 the Company began securing long-term, mutually beneficial written contracts with key customers. By entering into such agreements, the Company is assured of a market for its energy and can prudently invest in plant and equipment upgrades and enhanced delivery services that will benefit customers and make the utility more competitive. In 1994, the Company also formalized its economic development strategic plan, integrating many of its industry-attraction efforts with that of the city of Louisville and other regional businesses.
By using gas storage fields strategically, the Company can buy gas when prices are low, store it, and retrieve the gas when demand is high. Accessing least cost gas was made easier in November 1993 when FERC's Order No. 636 went into effect. Previously, the Company and other utilities purchased most of their gas services from pipeline companies. The order "unbundled" gas services, allowing utilities to purchase gas, transportation, and storage services separately from many different sources. Currently, the Company buys competitively priced gas from several large producers under contracts of varying duration. By purchasing from multiple suppliers, and storing any excess gas, the Company is able to secure favorably priced gas for its customers. Without storage capacity, the Company would be forced to buy additional gas when customer demand increases, which is usually when the price is highest. See FERC Order No. 636 under Item 7 for a further discussion.
The Company is experiencing some of the issues common to electric and gas utility companies, namely, increased competition for customers and costs of compliance with environmental laws and regulations.
For the year ended December 31, 1994, 74% of total operating revenues was derived from electric operations and 26% from gas operations. Electric and gas operating revenues and the percentages by classes of service on a combined basis for this period were as follows:
See Note 13 of Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 1994.
Electric Operations
The sources of electric operating revenues and the volumes of sales for the three years ended December 31, 1994, were as follows:
At December 31, 1994, the Company had 340,810 electric customers.
The Company uses efficient coal-fired boilers that are fully equipped with sulfur dioxide removal systems to generate electricity. The Company's system wide emission rate for sulfur dioxide in 1994 was approximately .84 lbs./MMBtu of heat input, which is significantly below the Phase II limit of 1.2 lbs./MMBtu established by the Clean Air Act Amendments for the year 2000.
On Monday, August 30, 1993, the Company set a record local peak load of 2,239 Mw, when the temperature at the time of peak reached 94 degrees F (average for the day was 84 degrees F). The 1994 maximum local peak load of 2,219 Mw occurred on Wednesday, June 15, when the temperature at the time of peak was 95 degrees F (average for the day was 85 degrees F). The record system peak of 3,223 Mw (which included purchases from and short-term sales to other electric utilities) occurred on Thursday, May 30, 1991.
The Company's current reserve margin is 16%. At February 28, 1995, the Company owned steam and combustion turbine generating facilities with a capacity of 2,613 Mw and an 80 Mw hydroelectric facility on the Ohio River. See Item 2, Properties.
The Company is a participating owner with 14 other electric utilities of Ohio Valley Electric Corporation (OVEC) whose primary customer is the Portsmouth Area uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio. The Company has electric transmission interconnections and/or interconnection/interchange agreements with PSI Energy, Kentucky Utilities Company, Southern Indiana Gas and Electric Company, The Cincinnati Gas & Electric Company, Indiana Michigan Power Company, OVEC, Big Rivers Electric Corporation, Tennessee Valley Authority, Wabash Valley Power Association, Indiana Municipal Power Agency, East Kentucky Power Cooperative (East Kentucky), Illinois Municipal Electric Agency, Jacksonville Electric Authority, and Ogelthorpe Power Corporation providing for various interchanges, emergency services, and other working arrangements.
The Company entered into an agreement with East Kentucky to provide about 40 megawatts of electricity to Gallatin Steel Company's (Gallatin) new steel mill in north central Kentucky. The agreement will continue for 10 years and is expected to result in approximately $6 million of revenues annually. Gallatin makes steel for manufacturing plants in Kentucky. The Company will supply the electricity from its power plants in the Louisville area. This transaction was negotiated by LPM, an affiliate of the Company, and the terms of the transaction were approved by the Kentucky Commission.
The Company and East Kentucky had an agreement that allowed East Kentucky to purchase power during its peak season, and the Company to sell power during its off-peak season. The
agreement entitled East Kentucky to buy from the Company up to 145 megawatts from mid-December to mid-February through 1994-95.
On February 28, 1991, the Company sold a 12.12% ownership interest in Trimble County Unit 1 to the Illinois Municipal Electric Agency (IMEA), based in Springfield, Illinois, which is an agency of 30 municipalities that own and operate their own electric systems. On February 1, 1993, the Indiana Municipal Power Agency (IMPA), based in Carmel, Indiana, purchased a 12.88% interest in the Trimble County Unit. IMPA is composed of 31 municipalities that have joined together to meet their long-term electric power needs. Both IMEA and IMPA pay their proportionate share for operation and maintenance expenses of the Unit and for fuel and reactant used. They are also responsible for their proportionate share of incremental capital assets acquired.
Electric and magnetic fields (sometimes referred to as EMF) surround electric wires or conductors of electricity such as electrical tools, household wiring and appliances, and high voltage electric transmission lines such as those owned by the Company. Certain studies have suggested a possible association between electric and magnetic fields and adverse health effects. The Electric Power Research Institute, of which the Company is a participating member, has expended approximately $75 million since 1987 in its investigation and research with regard to possible health effects posed by exposure to electric and magnetic fields.
Gas Operations
The sources of gas operating revenues and the volumes of sales for the three years ended December 31, 1994, were as follows:
At December 31, 1994, the Company had 265,688 gas customers.
The Company has underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers.
Reflecting the changing nature of the gas business, a number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through the Company's distribution system. Generally, transportation of natural gas for the Company's customers does not have an adverse effect on earnings because of the offsetting decrease in gas supply expenses. Transportation rates are designed to make the Company economically indifferent as to whether gas is sold or merely transported.
The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees F. During 1994, the maximum day gas sendout was 524,000 Mcf, occurring on January 15, when the average temperature for the day was 2 degrees F. Supply on that day consisted of 176,000 Mcf from purchases, 314,000 Mcf delivered from underground storage, and 34,000 Mcf transported for industrial customers. For further discussion, see Gas Supply.
In 1994, the Company experienced its first full year operating under FERC Order No. 636. While the Company had previously been able to purchase natural gas and pipeline transportation services from Texas Gas Transmission Corporation (Texas Gas), the Company now purchases only transportation services from Texas Gas pursuant to its FERC-approved tariff and acquires its supply of natural gas from other sources. For further discussion see Gas Supply and Note 10 of Notes to Financial Statements under Item 8.
Regulation and Rates
The Kentucky Commission has regulatory jurisdiction over the rates and service of the Company and over the issuance of certain of its securities. The Company is a "public utility" as defined in the Federal Power Act, and is subject to the jurisdiction of the Department of Energy and the FERC with respect to the matters covered in such Act, including the sale of electric energy at wholesale in interstate commerce. In addition, the FERC has sole jurisdiction over the issuance by the Company of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation under Item 7 and Notes 2 and 11 of Notes to Financial Statements under Item 8.
Increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all of the Company's electric customers by means of the Company's fuel adjustment clause. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals for the purpose of additional examination and transfer of the then current fuel adjustment charge or credit to the base charges. The Commission also requires that electric utilities, including the Company, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities.
The Company's gas rates contain a gas supply clause (GSC), whereby increases or decreases in the cost of gas supply are reflected in the Company's rates, subject to approval of the Kentucky Commission. The GSC procedure prescribed by order of the Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.
On January 1, 1994, the Company implemented a Commission approved demand side management (DSM) program. The program contains a rate mechanism that provides for the recovery of DSM program costs, allows the Company to recover revenues due to lost sales associated with the DSM programs and provides the Company an incentive for implementing DSM programs. See Rates and Regulation under Item 7 for a further discussion of DSM.
On October 7, 1994, the Company filed an application with the Kentucky Commission in which it requested approval of an environmental cost recovery surcharge to recover certain costs required to comply with the Federal Clean Air Act, as amended, and those federal, state, and local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal. Under state law, the Commission has until April 7, 1995, to rule on the application. If the Company's application is approved as filed, the surcharge will increase electric revenues by approximately $5.5 million in 1995 and $8.3 million in 1996. The Commission has previously approved environmental cost recovery surcharges for two other regulated electric utilities in Kentucky.
A management audit of Louisville Gas and Electric Company, which began in September 1994, is nearing completion. Vantage Consulting Inc. is conducting the audit under contract to the Kentucky Commission. Vantage has interviewed some 300 employees and the Company has made written responses to more than 800 requests for data and documents. The final report is not expected until June. A similar audit of the Company was conducted in 1986 under a mandate from the 1984 Kentucky General Assembly that requires such audits of the Commonwealth's 10 largest utilities.
As part of the corporate reorganization whereby the Company became the subsidiary of LG&E Energy Corp., the Company obtained the approval of the Kentucky Commission. The order of the Kentucky Commission authorizing the Company to reorganize into a holding company structure contains certain provisions, which, among other things, ensure the Kentucky Commission access to books and records of Energy Corp. and its affiliates which relate to transactions with the Company; require Energy Corp. and its subsidiaries to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company's customers; and preclude the Company from guaranteeing any obligations of Energy Corp. without prior written consent from the Kentucky Commission. In addition, such order provides that the Company's Board of Directors has the responsibility to use its dividend policy consistent with preserving the financial strength of the Company and that the Kentucky Commission, through its authority over the Company's capital structure, can protect the Company's ratepayers from the financial effects resulting from non-utility activities.
Construction Program and Financing
The Company's construction program is designed to assure that there will be adequate capacity to meet the future electric and gas needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. The Company's estimates of its construction expenditures can vary substantially due to numerous items beyond the Company's control, such as changes in rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.
At December 31, 1994, the Company's embedded cost of long-term debt was 6.5% and its ratio of earnings to fixed charges was 3.14. See Exhibit 12. For a further discussion of construction expenditures and financing, see Liquidity and Capital Resources under Item 7.
During the five years ended December 31, 1994, gross property additions amounted to $501 million. Internally generated funds for the five year period were sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 20% of total utility plant at December 31, 1994, and consisted of $391 million for electric properties and $110 million for gas properties. Gross retirements during the same period were $55 million, consisting of $44 million for electric properties and $11 million for gas properties.
Coal Supply
Approximately 90% of the Company's present electric generating capacity is coal-fired, the remainder being made up of a hydroelectric plant and combustion turbine peaking units fueled by natural gas and oil. Coal will be the predominant fuel used by the Company in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies. The Company has no nuclear generating units and has no plans to build any in the foreseeable future.
The Company has entered into coal supply agreements with various suppliers for coal deliveries for 1995 and beyond. The Company normally augments its coal supply agreements with spot market purchases which, during 1994, were about 10% of total purchases. The Company has a coal inventory policy, which is in compliance with the Kentucky Commission's directives and which the Company believes provides adequate protection under most contingencies. The Company had on hand at December 31, 1994, a coal inventory of approximately 580,000 tons, or a 35 day supply.
The Company expects, for the foreseeable future, to continue purchasing most of its coal from western Kentucky and southwest Indiana, which has a sulfur content in the 2%-3.5% range. The abundant supply of this relatively low priced coal, combined with present and future desulfurization technologies, is expected to enable the Company to continue to provide adequate electric service in a manner acceptable under existing environmental laws and regulations.
Coal for the Company's Mill Creek plant is delivered by rail and barge, whereas deliveries to the Cane Run plant are primarily by rail and also by truck. Deliveries to the Trimble County plant are by barge only.
The average delivered cost of coal purchased by the Company, per ton and per million Btu, for the periods shown were as follows:
Gas Supply
During 1994, the Company experienced its first full year of operation under FERC Order No. 636. Although the Company continues to transport natural gas supplies through Texas Gas at rates and terms regulated by the FERC, the Company now purchases its supply of natural gas from other sources.
As a result of FERC Order No. 636 and effective November 1, 1993, the Company entered into new transportation service agreements with Texas Gas. These agreements provide for 30,000 MMBtu (29,268 Mcf) per day in Firm Transportation (FT) throughout the year. This FT agreement expires October 31, 1995. During the winter months, the Company also has 184,900 MMBtu (180,390 Mcf) per day in No-Notice Service (NNS); during the summer months that NNS level is 135,000 MMBtu (131,707 Mcf) per day. The Company's NNS agreements with Texas Gas incorporate terms of two, five, and eight years, and include unilateral roll-over provisions at the Company's option. These transportation services are provided by Texas Gas pursuant to its FERC-approved tariff.
The Company has also entered into a series of long-term firm supply arrangements with various suppliers in order to meet its firm sales obligations. The gas supply arrangements include pricing provisions which are market-responsive. These firm supplies, in tandem with pipeline transportation services, provide the reliable and flexible supply needed to replace the bundled sales service supplied by the pipeline prior to the implementation of FERC Order No. 636.
During 1995, the Company will be participating in several regulatory proceedings at FERC. In particular, the Company will be involved in reviewing Texas Gas' most recent rate filing, and Texas Gas' filing to recover certain transition costs associated with the FERC-mandated implementation of FERC Order No. 636. As a separate matter, the Kentucky Commission has indicated in an order issued in its Administrative Case No. 346 that transition costs, which are clearly identified as being related to the cost of the commodity itself, are appropriately recoverable as a gas cost through the Company's gas supply clause. See Note 10 of Notes to Financial Statements under Item 8.
The Company operates five underground gas storage fields with a current working gas capacity of 14.6 million Mcf. Gas is purchased and injected into storage during the summer season and is then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter heating season.
The estimated maximum deliverability from storage during the early part of the 1993-1994 heating season was approximately 373,000 Mcf per day. Deliverability decreases during the latter portion of the heating season as the storage inventory is reduced by seasonal withdrawals.
The average cost per Mcf of natural gas purchased by the Company was $2.78 in 1994, $2.91 in 1993, and $2.77 in 1992.
Environmental Matters
Protection of the environment is a major priority for the Company. The Company engages in a variety of activities within the jurisdiction of federal, state, and local regulatory agencies. Those agencies have issued the Company permits for various activities subject to air quality, water quality,
and waste management laws and regulations. For the five year period ending with 1994, expenditures for pollution control facilities represented $106 million or 21% of total construction expenditures. The cost of operating and maintaining scrubber-related facilities amounted to $22 million in both 1994 and 1993. The Company's anticipated capital expenditures for 1995 to comply with environmental laws are approximately $16 million. See Note 10 of Notes to Financial Statements under Item 8 for a discussion of specific environmental proceedings affecting the Company.
Labor Relations
The Company's 1,625 operating, maintenance and construction employees are members of the International Brotherhood of Electrical Workers (IBEW) Local 2100. The current three-year contract will expire in November 1995.
Employees
The Company had 2,650 full-time employees at December 31, 1994. During the last quarter of 1993, the Company eliminated a number of full-time positions. See Note 5 of Notes to Financial Statements under Item 8 for a further discussion of this matter.
ITEM 2.
ITEM 2. PROPERTIES.
At February 28, 1995, the Company owned the following electric generating stations:
The Company's steam stations consist mainly of coal-fired units except for Cane Run Unit 3 which must use natural gas because of restrictions mandated by environmental regulations.
The Company also owns an 80 Mw hydroelectric generating station located in Louisville, operated under license issued by the FERC.
At December 31, 1994, the Company's electric transmission system included 21 substations with a total capacity of approximately 10,623,697 Kva and approximately 648 structure miles of lines. The electric distribution system included 83 substations with a total capacity of approximately 3,068,277 Kva, 3,505 structure miles of overhead lines, 233 miles of underground conduit, and 5,335 miles of underground conductors.
The Company's gas transmission system includes 177 miles of transmission mains, and the gas distribution system includes 3,312 miles of distribution mains.
The Company operates underground gas storage facilities with a current working gas capacity of approximately 14.6 million Mcf. See Gas Supply under Item 1.
In 1990, the Company entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease is for a period of 15 years and is scheduled to expire June 30, 2005.
Other properties owned by the Company include office buildings, service centers, warehouses, garages, and other structures and equipment, the use of which is common to both the electric and gas departments.
The trust indenture securing the Company's First Mortgage Bonds constitutes a direct first mortgage lien upon substantially all property owned by the Company.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
Rates, Regulatory Matters, and Trimble County Generating Plant
For a discussion of current regulatory matters and a detailed discussion of the current status concerning Trimble County Unit 1, see Rates and Regulation under Item 7 and Notes 2 and 11 of Notes to Financial Statements under Item 8.
Statewide Power Planning
As required by the regulations of the Kentucky Commission, on November 15, 1993, the Company filed its 1993 biennial Integrated Resource Plan with the Kentucky Commission. The plan, which updates the Company's first Integrated Resource Plan filed in 1991, proposes to meet customers' future demand through 2007 by adding resources in small increments such as short-term power purchases (1996-1999), a customer-owned standby generation program (1997), two combustion turbines (1999-2000), an air conditioner load controls program (1997, 2001-2003), an upgrade to the Company's existing hydroelectric plant (2003), and a compressed air energy storage plant (2004). The Kentucky Commission staff is reviewing the Company's plan, and is expected to issue its report
and recommendations concerning the plan during the first quarter of 1995. The Kentucky Commission's regulations do not require it to hold any hearings or issue any formal orders regarding the plan.
Environmental
For a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run generating plants, manufactured gas plant sites, and certain other environmental issues, see Note 10 of Notes to Financial Statements under Item 8.
Other
The Company is a defendant in lawsuits seeking compensatory and, in certain instances, punitive damages. To the extent that damages are assessed in any of these lawsuits, the Company believes that its insurance coverage is adequate and that the effect of any such damages will not be material to the Company's results of operation or financial position.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
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Executive Officers of the Company. Effective Date of Election to Name Age Position Present Position - ---- --- -------- -----------------
Roger W. Hale 51 Chairman of the Board and Chief Executive Officer January 1, 1992
Victor A. Staffieri 39 President January 1, 1994
John R. McCall 51 Executive Vice President, General Counsel and Corporate Secretary July 1, 1994
David R. Carey 41 Senior Vice President, Operations January 1, 1994
M. Lee Fowler 58 Vice President and Controller September 1, 1988
Wendy C. Heck 41 Vice President, Information Services January 1, 1994
Chris Hermann 47 Vice President and General Manager, Wholesale Electric Business January 1, 1993
Rebecca L. Holt 35 Vice President, Gas Service Business February 15, 1995
Charles A. Markel III 47 Treasurer January 1, 1993
The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the Annual Meeting of Stockholders, scheduled to be held April 25, 1995.
There are no family relationships between executive officers of the Company.
Mr. Hale, Mr. Carey, Mr. Fowler, Ms. Heck, Mr. Hermann, and Mr. Markel have been employed for more than five years in executive or management positions with the Company. Prior to election to the position shown in the table, the following executive officers held other positions with the Company since January 1, 1990: Mr. Hale was President and Chief Executive Officer prior to February 1990, and Chairman of the Board, President and Chief Executive Officer thereafter; Mr. Carey was Vice President-Marketing and Sales prior to July 1990, Vice President-Marketing and Planning prior to January 1992, Vice President-Marketing and General Manager, Electric Service, prior to January 1993, and Vice President and General Manager, Retail Electric Business thereafter; Ms. Heck was Vice President-Internal Auditing prior to January 1992, Vice President-Fuels and Operating Services prior to January 1993, and Vice President-Fuels and Information Services thereafter; Mr. Hermann was General Manager-Power Production prior to January 1992 and General Manager-Wholesale Electric thereafter; Mr. Markel was Vice President and Treasurer prior to March 1990, Vice President-Finance and Treasurer prior to January 1992, and Senior Vice President and Chief Financial Officer thereafter. Effective January 1993, Mr. Markel was named Corporate Vice President-Finance and Treasurer of the parent company, LG&E Energy Corp.
Prior to election to his current position, Mr. Staffieri was Senior Vice President-Public Policy, and General Counsel of the Company, and prior to November 1992, Senior Vice President, General Counsel and Corporate Secretary. Prior to March 1992, Mr. Staffieri was employed by Long Island Lighting Company and held the position of General Counsel and Secretary.
Prior to election to his current position, Mr. McCall was Partner and Litigation Chairman of Brown, Todd & Heyburn, a law firm.
Prior to election to her current position, Ms. Holt was employed by South Carolina Electric and Gas Company and held the position of General Manager, Gas Operations from July 1994 to February 1995, Division Manager, Central Division-Gas Operations prior to July 1994, General Manager, Northern Division-Gas Operations prior to February 1992, and Manager, Columbia Gas Operations prior to July 1990.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All Louisville Gas and Electric Company common stock, 21,294,223 shares, is held by LG&E Energy Corp. Therefore, there is no public trading market for the Company's common stock.
The following table sets forth the cash distributions on common stock paid to LG&E Energy Corp. for the periods indicated:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION.
The following discussion and analysis by management focuses on those factors that had a material effect on the Company's financial results of operations and financial condition during 1994, 1993, and 1992 and should be read in connection with the financial statements and notes thereto.
Results of Operations
Net Income Available for Common Stock
In 1994 the Company's net income available for common stock decreased $32.1 million. This decrease was due to the write-off of certain non-recurring items ($23.8 million), the expense of establishing a charitable foundation ($8.9 million), and the adoption of Statement of Financial Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS ($3.4 million). Without consideration of the charges against income discussed above, the Company's 1994 income would have increased $3.9 million over 1993. This improvement is primarily due to increased sales of electricity to retail customers and reduced interest on debt due to favorable refinancing activities in 1993.
The $17.9 million increase in earnings for 1993 over 1992 resulted primarily from increased electric sales attributable to warmer summer weather experienced in 1993, higher sales to other utilities, reduced costs for debt and preferred stock attributable to favorable refinancing activities, and a gain recognized on the sale of the remaining disallowed portion of the Trimble County plant to the Indiana Municipal Power Agency (IMPA). These items were partially offset by a higher level of operation and maintenance expense.
Rates and Regulation
The Company is subject to the jurisdiction of the Public Service Commission of Kentucky (Kentucky Commission or Commission) in virtually all matters related to electric and gas utility regulation, and as such, its accounting is subject to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71). Given the Company's competitive position in the market and the status of regulation in the state of Kentucky, the Company has no plans or intentions to discontinue its application of SFAS No. 71. See Note 2 of Notes to Financial Statements under Item 8.
Item 8.
Depreciation and amortization increased in both 1994 and 1993 because of additional depreciable plant in service.
Variations in income tax expenses are largely attributable to changes in pre-tax income and an increase in the corporate Federal income tax rate from 34% to 35%, effective January 1, 1993.
Other income and (deductions) increased $.5 million in 1994 partially due to recognition of a gain on the sale of construction equipment. Other income and (deductions) increased in 1993 primarily because of a $3.2 million after-tax gain recorded on the sale of a 12.88% ownership interest in the Trimble County plant to IMPA. See Note 7 of Notes to Financial Statements under Item 8 for further detail.
Contribution to the charitable foundation reflects the expense associated with establishing a tax-exempt foundation during 1994. Contributions made from this Foundation will not be charged against income, and therefore, will not affect the Company's net income in the future. See Note 3 of Notes to Financial Statements under Item 8.
Interest charges decreased in 1994 because of the lower composite interest rate on outstanding debt, which reflects the full year effect of the Company's 1993 aggressive program to refinance approximately $205 million of outstanding debt at lower interest rates. Interest charges also decreased in 1993 as compared to 1992 primarily because of this refinancing program. Since 1992, an immaterial component of interest expense has been the cost associated with interest rate swaps. See Liquidity and Capital Resources.
Preferred dividends reflect the lower dividends that resulted from the Company's refunding its $25 million, $8.90 Series with a $5.875 Series in May 1993.
The rate of inflation may have a significant impact on the Company's operations, its ability to control costs, and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.
LIQUIDITY AND CAPITAL RESOURCES
The Company's need for capital funds is primarily related to the construction of plant and equipment necessary to meet the needs of electric and gas utility customers and protection of the environment.
1994 Capital Requirements
New construction expenditures for 1994 were $95 million compared with $99 million for 1993 and $101 million for 1992.
Past Financing Activities
During 1994, 1993, and 1992, the Company's primary source of capital was internally generated funds from operating cash flows. Internally generated funds provided financing for 100% of the Company's construction expenditures for 1994 and 1993 and 87% of utility capital expenditures in 1992. Variations in accounts receivable and accounts payable are not generally significant indicators of the Company's liquidity, as such variations are primarily attributable to fluctuations in weather in the Company's service territory, which has a direct effect on sales of electricity and gas. In 1994, accounts receivable and accounts payable were lower due to warmer weather in the last quarter of the year as compared to 1993.
In 1993, the Company refinanced approximately $205 million of its long-term debt and $25 million of its preferred stock. These refinancings produced significant savings from lower interest rates and preferred dividend rates in 1994 and 1993. See Note 8 of Notes to Financial Statements under Item 8.
The Company's liquidity was also positively affected in 1993 by the sale of a 12.88% portion of the Company's Trimble County Generating Unit. At December 31, 1994, marketable securities classified as Other Property and Investments amounted to $50 million. See Note 4 of Notes to Financial Statements under Item 8.
The Company has outstanding interest rate swap agreements with a notional amount of $30 million. These swaps were entered into as a standard hedging device in connection with the 1992 issuance of the Company's Pollution Control Bonds Series S, due September 1, 2017. The swaps are designed to reduce the Company's exposure to interest rate risk. Under the agreements, the Company pays a fixed rate of 4.35% on $15 million for a five-year period and 4.74% on $15 million for a seven-year period resulting in interest payments based on a composite rate of 4.55% in 1994, 1993, and 1992. In return, the Company receives a floating rate based on the weighted average JJ Kenny index. The Company received interest at composite rates of 2.84%, 2.38%, and 2.73% in 1994, 1993, and 1992, respectively.
Future Capital Requirements
Future financing requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate increases allowed by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. The Company estimates construction expenditures will total $200 million for 1995 and 1996. In addition, expected capital requirements for 1996 include $16 million to retire long-term debt.
Future Sources of Financing
Internally generated funds from operations are expected to fund substantially all anticipated construction expenditures in 1995 and 1996.
At December 31, 1994, the Company had unused lines of credit of $145 million for which it pays commitment fees. These credit facilities are scheduled to expire at various periods during 1995 and 1996 and management intends to renegotiate them when they expire.
To the extent permanent financings are needed in 1995 and 1996, the Company expects that it will have ready access to the securities markets to raise needed funds.
Environmental Matters
The Clean Air Act Amendments of 1990 impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. All of the Company's coal-fired boilers are equipped with sulfur dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates required by the year 2000 under the legislation. However, as part of its ongoing construction program, the Company has spent $10 million to date and anticipates incurring capital expenditures of approximately $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the legislation on the Company is expected to be minimal. The Company is well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities.
Reference is made to Note 10 of Notes to Financial Statements, Environmental, under Item 8 for a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run electric generating plants, manufactured gas plant sites, and certain other environmental issues.
Energy Policy Act of 1992
The Energy Policy Act of 1992 is designed to give utilities a wider choice of sources for their electrical supply than previously available, while creating generating supply options that did not exist under the old law. In passing this legislation, Congress also anticipated that greater competition among electric supply options should result in lower consumer rates. The Company plans to aggressively pursue opportunities created by a more competitive electric power market.
FERC Order No. 636
In 1994, the Company experienced its first full year of operations under the provisions of Order No. 636. During 1994, the Company paid and began recovering from its customers approximately $2.8 million in transition costs under Order No. 636. It is estimated that $6 million to $8 million in additional transition costs will be incurred by the Company during 1995, and these costs are also expected to be recovered from customers. See FERC Order No. 636 in Note 10 of Notes to Financial Statements under Item 8 for further discussion.
FUTURE OUTLOOK
Business Realignment
Effective January 1, 1994, LG&E Energy Corp. realigned its business to reflect its outlook for rapidly emerging competition in all segments of the energy services industry. Under the realignment, a national business unit, LG&E Energy Services was formed to develop and manage all of its utility and non-utility electric power generation and concentrate on the marketing and brokering of wholesale electric power on a regional and national basis. Louisville Gas and Electric Company, LG&E Energy Corp.'s principal subsidiary, will increase its focus on customer service and develop more customer options as the utility industry becomes more competitive.
As part of the business realignment, a new subsidiary was formed to market power throughout the United States. LG&E Power Marketing Inc. (LPM), an indirect wholly owned subsidiary of LG&E Energy Corp., was among the first utility-affiliated marketers in the country to secure FERC approval to sell power at market-based rates and engage in wholesale power marketing activities.
The realignment does not affect LG&E Energy Corp.'s legal structure, regulation of the Company by the Commission or LG&E Energy Corp.'s status as an exempt holding company.
Gallatin Steel Company
The Company entered into an agreement with East Kentucky Power Cooperative, Inc. to provide about 40 megawatts of electricity to Gallatin Steel Company's (Gallatin) new steel mill in north central Kentucky. The agreement will continue for 10 years and is expected to result in approximately $6 million of revenues annually. Gallatin makes steel for manufacturing plants in Kentucky. The Company will supply the electricity from its power plants in the Louisville area. This transaction was negotiated by LPM, and the terms of the transaction were approved by the Commission.
Competition
The Company has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; a write-off of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee involvement and training; and a major realignment and formation of new business units.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Thousands of $)
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Thousands of $)
The accompanying notes are an integral part of these financial statements.
LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Thousands of $)
The accompanying notes are an integral part of these financial statements.
LOUISVILLE GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Louisville Gas and Electric Company (the Company) completed a corporate restructuring on August 17, 1990, pursuant to which the Company became the primary subsidiary of LG&E Energy Corp. The Company is a regulated public utility that is engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas. LG&E Energy Corp. is an exempt energy services holding company with wholly owned subsidiaries consisting of the Company and LG&E Energy Systems Inc., a non-regulated subsidiary. All of the Company's Common Stock is held by LG&E Energy Corp.
Certain reclassifications have been made to the 1993 and 1992 financial statements to conform with the 1994 presentation with no impact on previously reported income.
UTILITY PLANT. The Company's plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base, and, accordingly, the Company has not recorded any allowance for funds used during construction.
The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost plus removal expense less salvage value is charged to the reserve for depreciation. When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized.
DEPRECIATION. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for 1994 were 3.3% (3.2% electric, 3.3% gas, and 5% common); for 1993 3.3% (3.2% electric, 3.2% gas, and 5% common); and for 1992, 3.3% (3.2% electric, 3.2% gas, and 5.4% common) of average depreciable plant.
CASH AND TEMPORARY CASH INVESTMENTS. The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value.
DEFERRED INCOME TAXES. Deferred income taxes have been provided for all book-tax temporary differences.
The Company adopted Statement of Financial Accounting Standards No. 109, ACCOUNTING FOR INCOME TAXES (SFAS No. 109), effective January 1, 1993. Regulatory assets and liabilities have been established to recognize the future revenue requirement impact from the deferred income taxes which were not immediately recognized in operating results because of ratemaking treatment. The adoption of SFAS No. 109 did not have a material impact on the results of operations or financial position.
INVESTMENT TAX CREDITS. Investment tax credits resulted from provisions of the tax law that permitted a reduction of the Company's tax liability based on credits for certain construction expenditures. Investment tax credits deferred and charged to income in prior years are being amortized to income over the estimated lives of the related property that gave rise to the credits.
DEBT PREMIUM AND EXPENSE. Debt premium and expense are amortized over the lives of the related debt issues, consistent with regulatory practices.
REVENUE RECOGNITION. Revenues are recorded based on service rendered to customers through month end. The Company accrues an estimate for unbilled revenues from the date of each meter reading date to the end of the accounting period. Effective January 1, 1994, under an agreement approved by the Public Service Commission of Kentucky (Kentucky Commission or Commission), the Company implemented a demand side management program and a "decoupling mechanism," which allows the Company to recover a predetermined level of revenue on electric and gas residential sales. See Management's Discussion and Analysis, Rates and Regulation, under Item 7 for further discussion.
FUEL AND GAS COSTS. The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system.
INTEREST RATE CONTRACTS. Interest rate swaps are used by the Company to convert variable rate debt to a fixed rate. The cost or benefit of the interest rate swaps is recorded as a component of interest expense.
REVENUES AND CUSTOMER RECEIVABLES. The Company is an operating public utility that supplies natural gas to approximately 266,000 customers and electricity to approximately 341,000 customers in Louisville and adjacent areas in Kentucky. Customer receivables and gas and electric revenues arise from deliveries of natural gas and electric energy to a diversified base of residential, commercial and industrial customers and to public authorities and other utilities. For the year ended December 31, 1994, 74% of total operating revenue was derived from electric operations and 26% from gas operations.
NOTE 2 - RATES AND REGULATORY MATTERS
The Company conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by the Federal Energy Regulatory Commission (FERC) and the Kentucky Commission. The Company is subject to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71).
Under SFAS No. 71, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in the balance sheets as of December 31 (in thousands of $):
As of December 31, 1994, approximately $15 million of the Company's net regulatory assets are being recovered through rates charged to customers over periods ranging from three to 22 years. The Company expects to obtain recovery of the remaining regulatory assets in its next general rate case. For additional information regarding post-retirement benefits and early retirement/workforce reduction costs, deferred income taxes, and environmental costs, see Notes 5, 6, and 10, respectively. In early 1994, the Company, based on a re-evaluation of its regulatory strategy, wrote off certain regulatory assets included in the 1993 balance sheet. See Note 3, Non-Recurring Charges, for a further discussion.
In October 1994, the Company filed an application with the Kentucky Commission to implement an environmental cost recovery surcharge. The surcharge will allow the Company to recover certain costs incurred to comply with federal, state, and local environmental requirements. If approved by the Commission, the surcharge will take effect in May 1995. See Management's Discussion and Analysis, Rates and Regulation, under Item 7 for a further discussion.
NOTE 3 - NON-RECURRING CHARGES
As part of a study of LG&E Energy Corp.'s business strategy and realignment during 1994, the Company re-evaluated its regulatory strategy which previously had been to seek full recovery of certain costs deferred in accordance with prior precedents established by the Commission. As a result of this re-evaluation, the Company wrote off certain expenses that had previously been deferred amounting to approximately $38.6 million before taxes. While the Company continues to believe that it could have reasonably expected to recover these costs in future rate proceedings before the Commission, the Company decided to deduct these expenses currently and not seek recovery for such expenses in future rates due to increasing competitive pressures and the existing and anticipated future economic conditions. The items written off include costs incurred in connection with early retirements and workforce reductions that occurred in 1992 and 1993 which consist primarily of separation payments, enhanced early retirement benefits, and health care benefits; costs associated with property damage claims pertaining to particulate
emissions from its Mill Creek electric generating plant which primarily consist of spotting on automobile finish and aluminum siding; and certain costs previously deferred resulting from adoption in January 1993 of Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS.
In the first quarter of 1994, the Board of Directors of the Company approved the formation of a tax-exempt charitable foundation (Foundation) which will make charitable contributions to qualified persons and entities. In 1994, the Company recorded a pre-tax charge against income and made an irrevocable payment of $15 million to fund the Foundation. On June 6, 1994, the Internal Revenue Service issued a letter stating that it had determined the Foundation was exempt from Federal income tax under the Internal Revenue Code.
NOTE 4 - MARKETABLE SECURITIES AND OTHER FINANCIAL INSTRUMENTS
MARKETABLE SECURITIES. The Company adopted the provisions of Statement of Financial Accounting Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES, effective January 1, 1994. Accordingly, the Company's marketable securities have been determined to be "available-for-sale" and are stated at market value in the accompanying December 31, 1994, balance sheet. The available-for-sale category of investments results in the classification of unrealized gains and losses on investments in common equity, net of income taxes, until such gains and losses are realized, at which time they are recognized in earnings. Proceeds from sales of available-for-sale securities were $56,085,000, which resulted in realized gains of $1,557,000 and losses of $1,538,000, calculated using the specific identification method. The difference between amortized and unamortized cost basis of the Company's investments in marketable securities as of December 31, 1994, was immaterial.
Approximate cost, fair value, and other required information about the Company's available-for-sale securities by major security type as of December 31, 1994, follows (in thousands of $):
The Company's available-for-sale securities above include approximately $.6 million market value ($18.5 million notional amount) of short futures on U.S. Treasury Notes and Bonds maturing March 1995. The Company uses such instruments to hedge a major portion of its preferred equity portfolio to substantially reduce price volatility of the securities due to interest rate changes. The Company does not maintain any margin accounts relative to its investment positions.
The Company's available-for-sale securities are classified as Other Property and Investments in the accompanying 1994 balance sheet.
FINANCIAL INSTRUMENTS. Pursuant to Statement of Financial Accounting Standards No. 107, DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS, the Company is required to disclose the fair value of financial instruments where practicable. The disclosure of such information does not purport to be a market valuation of the Company as a whole. The carrying amounts of cash, accounts receivable, notes payable, and accounts payable reflected on the balance sheets approximates the fair value of these instruments due to the short duration to maturity.
The fair value for certain of the Company's investments and debt are estimated based on quoted market prices for those or similar instruments. Investments for which there are no quoted market prices are stated at cost because a reasonable estimate of fair value cannot be made without incurring excessive costs. The fair value of interest rate swaps is based on the quoted market price as provided by the financial institution which is the counterparty to the swap.
The cost and estimated fair value of the Company's financial instruments as of December 31, 1994 and 1993, are as follows (in thousands of $):
NOTE 5 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS. The Company has two non-contributory, defined-benefit pension plans, covering all eligible employees. Retirement benefits are based on the employee's years of service and compensation. The Company's policy is to fund annual actuarial costs, up to the maximum amount deductible for income tax purposes, as determined under the frozen entry age actuarial cost method.
In addition, the Company has a supplemental executive retirement plan that covers officers of the Company. The plan provides retirement benefits based on average earnings during the final three years prior to retirement, reduced by social security benefits, any pension benefits received from plans of prior employers, and by amounts received under the pension plans referred to above.
Pension costs were $4,423,000 for 1994, $2,669,000 for 1993, and $2,598,000 for 1992, of which approximately $693,000, $425,000, and $241,000, respectively, were charged to construction. The components of periodic pension expense are shown below (in thousands of $):
The assets of the plans consist primarily of common stocks, corporate bonds, United States government securities, and interests in a pooled real estate investment fund.
The funded status of the pension plans at December 31 is shown below (in thousands of $):
The projected benefit obligation was determined using an assumed discount rate of 8.5% for 1994 and 7.5% for 1993. An assumed annual rate of increase in future compensation levels ranged from 4.5% to 5% for 1994 and 3.5% to 4.5% for 1993. The assumed long-term rate of return on plan assets was 8.5% for 1994 and 1993. Transition assets and prior service costs are being amortized over the average remaining service period of active participants.
POST-RETIREMENT BENEFITS. The Company adopted Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS (SFAS No. 106), effective January 1, 1993. SFAS No. 106 requires the accrual of the expected cost of retiree benefits other than pensions during the employee's years of service with the Company. The Company is amortizing the discounted present value of the post-retirement benefit obligation at the date of adoption over 20 years.
The Company provides certain health care and life insurance benefits for eligible retired employees. Post-retirement health care benefits are subject to a maximum amount payable by the Company. Prior to January 1, 1993, the cost of retiree health care and life insurance benefits was generally recognized when paid. This cost was $1,078,000 for 1992. In 1993, the Company began to account for post-retirement benefits according to the provisions of SFAS No. 106.
In 1993, the Company, based on an order from the Commission, created a regulatory asset and deferred the level of SFAS No. 106 expense in excess of the previous level of pay-as-you-go expense. Therefore, the adoption of SFAS No. 106 did not have an effect on results of operations in 1993. However, in the first quarter of 1994, the Company began recognizing the excess SFAS No. 106 expense currently, including the amount previously deferred. See Note 3, Non-Recurring Charges.
The components of the net periodic post-retirement benefit cost as calculated under SFAS No. 106 are as follows (in thousands of $):
The accumulated post-retirement benefit obligation as calculated under SFAS No. 106 at December 31, is shown below (in thousands of $):
The accumulated post-retirement benefit obligation was determined using an assumed discount rate of 8.5% for 1994 and 7.5% for 1993. Assumed compensation increases for projected life insurance benefits for affected groups was 5% for 1994 and 4.5% for 1993. An assumed health care cost trend rate of 10.5% was assumed for 1994, gradually decreasing to 5.25% in ten years and thereafter.
A 1% increase in the assumed health care cost trend rate would increase the accumulated post-retirement benefit obligation by approximately $1 million and the annual service and interest cost by approximately $100,000. No funding has been established by the Company for post-retirement benefits.
POST-EMPLOYMENT BENEFITS. The Company adopted Statement of Financial Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS (SFAS No. 112) on January 1, 1994, as required. SFAS No. 112 requires the accrual of the expected cost of benefits to former or inactive employees after employment but before retirement. The cumulative effect of the accounting change was recorded in the first quarter of 1994 and decreased net income by $3.4 million.
EARLY RETIREMENT/WORKFORCE REDUCTION. During the last quarter of 1993, the Company eliminated approximately 350 full-time positions. The cost of the employee reduction program was approximately $11.5 million, and consisted primarily of separation payments, enhanced early retirement benefits, and health care benefits.
In 1992, an early retirement program was made available to all Company union employees who had reached age 55, or who had 35 years or more of continuous service regardless of age. The cost of the program was approximately $7 million and consisted primarily of enhanced early retirement and health care benefits.
THRIFT SAVINGS PLAN. The Company has a Thrift Savings Plan under Section 401(k) of the Internal Revenue Code. The plan covers all regular full-time employees with one year or more of service at the Company. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. The Company makes contributions to the plan by matching a portion of employee contributions according to a formula established by the plan. These costs were approximately $1,701,000 for 1994, $1,795,000 for 1993, and $767,000 for 1992. The increase in 1993 401(k) expenses over 1992 is due to the expansion of the program to the Company's union employees.
NOTE 6 - FEDERAL AND STATE INCOME TAXES
Components of income tax expense are shown in the table below (in thousands of $):
Variations in income tax expense are largely attributable to changes in pre-tax income.
Provisions for deferred income taxes-net consist of the tax effects of the following temporary differences (in thousands of $):
The net provisions for deferred income taxes decreased in 1994 due largely to recording certain liabilities which are not deductible until such liabilities are paid. Deferred income taxes attributable to depreciation and amortization decreased in 1993 because of the reversal of prior years' accumulated taxes as a result of the sale of a portion of Trimble County Unit 1. See Note 12, Jointly Owned Electric Utility Plant for a further discussion of the sale.
Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
The Company's effective income tax rate is computed by dividing the aggregate of current income taxes, deferred income taxes-net, and the amortization of investment tax credit, by net income before the deduction of such taxes. Reconciliation of the statutory Federal income tax rate to the effective income tax rate is shown in the table below:
NOTE 7 - OTHER INCOME AND (DEDUCTIONS)
Other income and (deductions) consisted of the following at December 31 (in thousands of $):
NOTE 8 - FIRST MORTGAGE BONDS
Annual requirements for the sinking funds of the Company's First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with the Pollution Control Bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166 2/3% of principal amounts of bonds otherwise
required to be so redeemed) have been applied in lieu of cash. It is the intent of the Company to apply property additions to meet 1995 sinking fund requirements of the First Mortgage Bonds.
The trust indenture securing the First Mortgage Bonds constitutes a direct first mortgage lien upon substantially all property owned by the Company. The indenture, as supplemented, provides in substance that, under certain specified conditions, portions of retained earnings will not be available for the payment of dividends on common stock. No portion of retained earnings is presently restricted by this provision.
Pollution Control Bonds (Louisville Gas and Electric Company Projects) issued by Jefferson and Trimble Counties, Kentucky, are secured by the assignment of loan payments by the Company to the Counties pursuant to loan agreements, and further secured by the delivery from time to time of an equal amount of the Company's First Mortgage Bonds, Pollution Control Series. First Mortgage Bonds so delivered are summarized in the Statements of Capitalization. No principal or interest on these First Mortgage Bonds is payable unless default on the loan agreements occurs. The interest rate reflected in the Statements of Capitalization applies to the Pollution Control Bonds.
In March 1993, due to the sale of 12.88% of Trimble County Unit 1, the Company completed the defeasance of $25 million of its Pollution Control Bonds ($16.665 million of the 7.625% Series and $8.335 million of the 6.55% Series).
The Company issued several series of lower interest bearing First Mortgage and Pollution Control Bonds in 1993 to refinance bonds with higher interest rates. In August 1993, the Company issued two separate series of Pollution Control Bonds (a $35.2 million, Variable Rate Series, which had an average interest rate of 3.740% at December 31, 1994, and 2.586% at December 31, 1993, and a $102 million, 5.625% Series) and redeemed five series of Pollution Control Bonds totaling $137.2 million with interest rates ranging from 6.125% to 6.7%. In August 1993, the Company also issued $42.6 million of 6% First Mortgage Bonds and redeemed two series of First Mortgage Bonds ($19.7 million at 8.25% and $21.362 million at 8.5%). In November 1993, the Company issued $26 million of Pollution Control Bonds, 5.45% Series and redeemed the $26 million, 9.75% Series.
The Company entered into an agreement in November 1993 with Goldman, Sachs & Co. to issue $40 million of tax-exempt Pollution Control Bonds in 1995 at a rate of 5.9%. The issuance of the bonds in 1995 is subject to certain conditions. If issued, the proceeds will be used to redeem, in 1995, the outstanding 9.25% series of Pollution Control Bonds due July 1, 2015.
The Company has outstanding interest rate swap agreements totaling $30 million. Under the agreements, which were entered into in 1992, the Company pays a fixed rate of 4.35% on $15 million for a five-year period and 4.74% on $15 million for a seven-year period. In return, the Company receives a floating rate based on the weighted average JJ Kenny index. The JJ Kenny index is a tax-exempt municipal bond interest rate index. These swaps were entered into as a standard hedging device in connection with the issuance of the Series S Pollution Control Bonds due September 1, 2017. The swaps are designed to reduce the Company's exposure to interest rate risk. The Company received interest at composite rates of 2.84%, 2.38%, and 2.73% in
1994, 1993, and 1992, respectively and paid interest at a composite rate of 4.55% pursuant to the swaps.
The Company's First Mortgage Bonds, 5.625% Series of $16 million is scheduled to mature in 1996 and the 6.75% Series of $20 million is scheduled to mature in 1998. There are no scheduled maturities of Pollution Control Bonds for the five years subsequent to December 31, 1994. The Company has no cash sinking fund requirements.
NOTE 9 - NOTES PAYABLE
The Company had no notes payable at December 31, 1994, or December 31, 1993.
At December 31, 1994, the Company had unused lines of credit of $145 million, for which it pays commitment fees. The credit lines are scheduled to expire at various periods throughout 1995 and 1996. Management intends to renegotiate these lines when they expire.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM. The Company had commitments, primarily in connection with its construction program, aggregating approximately $8 million at December 31, 1994. Construction expenditures for the calendar years 1995 and 1996 are estimated to total approximately $200 million.
FERC ORDER NO. 636. In 1994, the Company experienced its first full year operating under Order No. 636. Whereas the Company had previously purchased natural gas and pipeline transportation services from Texas Gas Transmission Corporation (Texas Gas), the Company now purchases only transportation services from Texas Gas and purchases natural gas from other sources.
Under Order No. 636 pipelines may recover costs associated with the transition to and implementation of this order from pipeline customers, including the Company. The Commission issued an order, based on proceedings that were held to investigate the impact of Order No. 636 on utilities and ratepayers in Kentucky, providing that transition costs assessed on utilities by the pipelines, which are clearly identifiable as being related to the cost of the commodity itself, are appropriate to be recovered from customers through the gas supply clause. During 1994, the Company paid and began recovering from its customers approximately $2.8 million in transition costs. It is estimated that $6 million to $8 million in additional transition costs will be incurred by the Company during 1995, and these costs are also expected to be recovered from customers. The Company is a party to proceedings before FERC which will determine a number of pipeline transition issues. Because of the impact such issues may have on future costs, management is unable to estimate the level of transition costs, if any, for years subsequent to 1995.
OPERATING LEASE. The Company has an operating lease for its corporate office building that is scheduled to expire in June 2005. Total expense in connection with this lease for 1994, 1993, and 1992 was $2,192,000, $2,436,000, and $2,478,000, respectively. The future minimum annual lease payments under the lease agreement for years subsequent to December 31, 1994, are as follows (in thousands of $):
1995. . . . . . . . . . . . . $ 2,499 1996. . . . . . . . . . . . . 2,850 1997. . . . . . . . . . . . . 2,850 1998. . . . . . . . . . . . . 2,850 1999. . . . . . . . . . . . . 2,850 Thereafter. . . . . . . . . . 18,960 -------
Total . . . . . . . . . . $ 32,859 ------- -------
ENVIRONMENTAL. The Clean Air Act Amendments of 1990 impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. The legislation is extremely complex and its effect will substantially depend on regulations issued by the U.S. Environmental Protection Agency (USEPA). The Company is closely monitoring the continuing rule-making process in order to assess the precise impact of the legislation on the Company. All of the Company's coal-fired boilers are equipped with sulfur dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates required by the year 2000 under the legislation. However, as part of its ongoing capital construction program, the Company has spent $10 million to date and anticipates incurring additional capital expenditures of approximately $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the legislation on the Company is expected to be minimal. The Company is well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities.
In 1992, the Company entered two agreed orders with the Air Pollution Control District (APCD) of Jefferson County in which the Company committed to undertake remedial measures to address certain particulate emissions and alleged excess sulfur dioxide emissions from its Mill Creek electric generating plant. In May 1994, the Company completed all specified remedial measures in accordance with the terms of the agreed orders. The Company has agreed to commence a joint field sampling program with the APCD to demonstrate the effectiveness of the remedial measures.
In August 1993, 34 persons filed a complaint in Jefferson Circuit Court against the Company seeking certification of a class consisting of all persons within 2.5 miles of the Mill Creek plant. The plaintiffs seek compensation for alleged personal injury and property damage attributable to emissions from the Mill Creek plant, injunctive relief, a fund to finance future medical monitoring of area residents, and other relief. In June 1994, the court denied the plaintiffs' motion for certification of the class and thus limited the scope of the litigation to the claims of the individual plaintiffs. The Company intends to vigorously defend itself in the pending litigation.
In an effort to resolve property damage claims relating to particulate emissions from the Mill Creek plant, in July 1993, the Company commenced extensive negotiations and property damage settlements with adjacent residents who are not parties to the pending litigation. The negotiations and settlements are continuing and the Company currently estimates that property
damage claims for the particulate emissions should be settled for an aggregate amount of approximately $15 million. Accordingly, the Company has recorded an accrual of this amount.
In response to a notification from the APCD that the Company's Cane Run plant may be the source of a potential exceedance of the National Ambient Air Quality Standards for sulfur dioxide, the Company submitted a draft action plan and modeling schedule to the APCD and USEPA. The APCD and USEPA have approved the submittals, and a Company contractor is currently conducting additional modeling activities. Although it is expected that corrective action will be accomplished through capital improvements, until the modeling activities are complete, the Company cannot determine the precise impact of this matter.
In March 1994, the APCD adopted a regulation requiring a 15% reduction from 1990 volatile organic compound (VOC) emissions from industrial sources. There are currently no demonstrated technologies for control of VOC emissions from coal-fired boilers. Consequently, compliance with the regulation could require limits on generation at the Mill Creek and Cane Run plants, unless the APCD adopts a provision for compliance through utilization of banked emission allowances. The Company is currently negotiating with the APCD in an effort to demonstrate its eligibility for an exclusion from the VOC reduction requirements.
The Company owns or formerly owned three primary sites where manufactured gas plant operations were located. Such manufactured gas plant operations, conducted in the 1838 to 1960 time period, typically produced coal tar byproducts and other constituents that may necessitate cleanup measures. The Company has completed an investigation of the level of contaminants present at the two company-owned sites, and the Company, along with the current owner of the third site and another party completed an investigation of the third site. Investigation and testing at these three sites has identified the presence of contaminants typical of manufactured gas operations. A report on the results of the investigation at each site has been prepared and submitted to the Kentucky Natural Resources and Environmental Protection Cabinet (KNREPC). The KNREPC will review the findings submitted by the Company, and through negotiations with the Company, the level of remediation required at each site will be determined. Although a precise determination of the costs associated with cleanup activities at these three sites cannot be made until the required level of remediation is established, management currently estimates that the total cost will fall within a range of $3 million to $12 million and has recorded an accrual of approximately $3 million in the accompanying financial statements.
In November 1993, the Company was served with a third-party complaint filed in federal district court in Illinois by three third-party plaintiffs. The third-party plaintiffs allege that the Company and 31 other parties are liable under the Comprehensive Environmental Response, Compensation, and Liability Act as amended (CERCLA) for $1.4 million in costs allegedly incurred by USEPA in conducting cleanup activities at the M.T. Richards Site in Crossville, Illinois. A number of de minimis third party defendants, including the Company, have commenced settlement discussions with the third-party plaintiffs. In the Company's opinion, the resolution of this issue will not have a material adverse impact on its financial position or results of operations.
In June 1992, USEPA identified the Company as a potentially responsible party (PRP) allegedly liable under CERCLA for $1.6 million in costs allegedly incurred by USEPA in cleanup of the Sonora Site and Carlie Middleton Burn Site located in Hardin County, Kentucky. The USEPA
has since increased the amount of its demand to $1.8 million to reflect additional cleanup costs. In September 1994, USEPA filed a CERCLA cost recovery action in U.S. District Court against the Company and six other parties. In the Company's opinion, the resolution of this issue will not have a material adverse impact on its financial position or results of operations.
In 1987, USEPA identified the Company as one of the numerous PRPs allegedly liable under CERCLA for the Smith's Farm Site in Bullitt County, Kentucky. In March 1990, USEPA issued an administrative order requiring the Company and 35 other PRPs to conduct certain cleanup activities. In February 1992, four PRPs filed a complaint in federal district court in Kentucky against the Company and 52 other PRPs. Under the law, each PRP could be held jointly and severally liable for the cost of site cleanup, but would have the right to seek contribution from other PRPs. In July 1993, upon motion of the plaintiffs, the federal court dismissed the Company and a number of others from the litigation in order to facilitate settlement negotiations among the parties. Cleanup costs for the site are currently estimated at approximately $70 million. The Company and several other parties have shared certain cleanup costs in the interim until a voluntary allocation of liability can be reached among the parties. It is not possible at this time to predict the outcome or precise impact of this matter. However, management believes that this matter should not have a material adverse impact on the financial position or results of operations of the Company as other financially viable PRPs appear to have primary liability for the site.
NOTE 11 - TRIMBLE COUNTY GENERATING PLANT
Trimble County Unit 1 (Trimble County), a 495-megawatt, coal-fired electric generating unit placed into service in December 1990, is currently the subject of an administrative proceeding before the Commission. This proceeding, which originally began in 1988, was initiated by the Commission to determine the appropriate ratemaking treatment to implement its 1988 decision that the Company should not be allowed to recover 25% of the cost of the Unit from ratepayers. As a result of a non-unanimous settlement agreement in the initial 1989 proceedings reached between the Company and the Commission staff, which was approved by the Kentucky Commission in October 1989, the Company returned to its customers $11.1 million through refunds and rate reductions. The Commission's approval of the settlement agreement was appealed by certain intervenors in the case who had not joined in the agreement. In April 1993, the Kentucky Court of Appeals held that the Commission exceeded its authority in approving the agreement, and ordered the Commission to hold new hearings on the underlying issues.
Pursuant to a Commission procedural order, the Company filed direct testimony on January 7, 1994, in which the Company recommended that the Commission allow it to recover the $11.1 million it refunded to customers under the 1989 settlement agreement. Testimony filed by intervenors recommended that the Commission order the Company to refund approximately $183 million, based upon their argument that the Company should refund 25% of the revenue requirements associated with Trimble County's construction-work-in-progress (CWIP) collected through rates over the course of the Trimble County construction project.
On March 25, 1994, the Kentucky Attorney General and the Jefferson County Attorney filed a motion with the Commission in which they requested that two of the three members of the Commission and certain unspecified Commission staff employees be recused from further participation in the case. The intervenors supported the motion by arguing that past statements and orders of the Commission in this and other proceedings showed that the Commissioners had
prejudged the issues relevant to the current proceeding. The issues referred to in the motion centered on the intervenors' claims that the Company should refund 25% of all revenues associated with Trimble County CWIP collected through rates during the course of the plant's construction.
On July 8, 1994, the Commission entered an order which denied the intervenors' motion. In the order, the Commission stated that it had not prejudged any issues but rather had decided a number of issues in past proceedings which are binding on it and all other parties. The Commission also stated that it had never implied in prior orders that the amounts of Trimble County CWIP included in rate base prior to the issuance of its July 1, 1988, order in Case No. 10064, a general rate case, would be subject to later review. The Commission concluded that the scope of the present case had been limited since at least 1985 when the Commission issued an order that put the Company on notice that in future rate cases the continuation of allowing a return on further additions to Trimble County CWIP would be an issue.
The Company believes that the Commission's July 8 order makes it unlikely that the Commission will entertain the position that the intervenors have taken in their previously-filed testimony that the Company refund approximately $183 million to its customers. The Company believes that remaining at issue is what amount, if any, of the approximately $30 million it collected subject to refund under a rate case order issued in 1988 should be returned to ratepayers. As discussed previously, approximately $11.1 million has already been returned to ratepayers under the 1989 settlement agreement. However, the Company is unable to predict the outcome of the Commission proceedings, or the amount of additional refunds or recoveries, if any, that may be ordered.
The Commission has set May 9, 1995, as the formal hearing date in the Trimble County proceedings. The purpose of the hearing is to determine the proper ratemaking treatment to exclude 25% of Trimble County from customer rates for the period from May 1988 to December 31, 1990. The Company's current rates, which became effective January 1, 1991, reflect the disallowance of 25% of the plant.
Reference is made to Note 12, Jointly Owned Electric Utility Plant, for a discussion of the sale of 25% of Trimble County.
NOTE 12 - JOINTLY OWNED ELECTRIC UTILITY PLANT
The Company owns a 75% undivided interest in Trimble County Unit 1. Accounting for the 75% portion of the Unit, which the Commission has allowed to be reflected in customer rates, is similar to the Company's accounting for other wholly owned utility plants.
Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA) purchased a 12.12% undivided interest in the Unit on February 28, 1991, and Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided interest on February 1, 1993. Each is responsible for their proportionate ownership share of operation and maintenance expenses and incremental assets, and for fuel used.
The following data represent shares of the jointly owned property:
NOTE 13 - SEGMENTS OF BUSINESS
The Company is an operating public utility engaged in the generation, transmission, distribution, and sale of electricity and the transmission, distribution, and sale of natural gas.
REPORT OF MANAGEMENT
The management of Louisville Gas and Electric Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report. These statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.
The Company's financial statements have been audited by Arthur Andersen LLP, independent public accountants. Management has made available to Arthur Andersen LLP all the Company's financial records and related data as well as the minutes of shareholders' and directors' meetings.
Management has established and maintains a system of internal controls that provide reasonable assurance that transactions are completed in accordance with management's authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by the Company's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal auditors. These recommendations for the year ended December 31, 1994 did not identify any significant deficiencies in the design and operation of the Company's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside directors. In carrying out its oversight role for the financial reporting and internal controls of the Company, the Audit Committee meets regularly with the Company's independent public accountants, internal auditors and management. The Audit Committee reviews the results of the independent accountants' audit of the financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Audit Committee also approves the annual internal auditing program, and reviews the activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Audit Committee at any time.
Louisville Gas and Electric Company maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure, and the confidentiality of proprietary information.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO LOUISVILLE GAS AND ELECTRIC COMPANY:
We have audited the accompanying balance sheets and statements of capitalization of Louisville Gas and Electric Company (a Kentucky corporation and a wholly owned subsidiary of LG&E Energy Corp.) as of December 31, 1994 and 1993, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule 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 referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As further discussed in Note 11, the potential amount of future rate refunds that may be required, if any, once the outcome of the legal and regulatory process is known, is uncertain at this time.
As discussed in Notes 1 and 5 to the financial statements, effective January 1, 1993, the Company changed its methods of accounting for income taxes and post-retirement benefits other than pensions, and effective January 1, 1994, the Company changed its method of accounting for post-employment benefits.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Louisville, Kentucky, Arthur Andersen LLP January 30, 1995
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SELECTED QUARTERLY FINANCIAL DATA (Unaudited) (Thousands of $)
Selected financial data for the four quarters of 1994 and 1993 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
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ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEMS 10, 11, 12 AND 13 are omitted pursuant to General Instruction G, inasmuch as the Company filed copies of a definitive proxy statement with the Commission on March 16, 1995, pursuant to Regulation 14A under the Securities Exchange Act of 1934. Such proxy statement is incorporated herein by this reference. In accordance with General Instruction G of Form 10-K, the information required by Item 10
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) 1. Financial Statements (included in Item 8): Statements of Income for the three years ended December 31, 1994 (page 23). Statements of Retained Earnings for the three years ended December 31, 1994 (page 23). Balance Sheets - December 31, 1994, and 1993 (page 24). Statements of Cash Flows for the three years ended December 31, 1994 (page 25). Statements of Capitalization - December 31, 1994, and 1993 (page 26). Notes to Financial Statements (pages 27-43). Report of Management (page 44). Report of Independent Public Accountants (page 45). Selected Quarterly Financial Data for 1994 and 1993 (page 46).
2. Financial Statement Schedule (included in Part IV): Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 1994 (page 60).
All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements.
3. Exhibits:
Exhibit No. Description ------- -----------
3.01 Copy of Restated Articles of Incorporation, as amended. [Filed as Exhibit 3.01 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
3.02 Copy of Amendment to Articles of Incorporation, effective May 25, 1989. [Filed as Exhibit 3.02 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
3.03 Copy of Amendment to Articles of Incorporation, effective February 6, 1992. [Filed as Exhibit 3.03 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
3.04 Copy of Amendment to Articles of Incorporation, effective April 8, 1993. [Filed as Exhibit 3.04 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
3.05 Copy of Amendment to Articles of Incorporation, effective May 19, 1993. [Filed as Exhibit 3.05 to the Company's Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
3.06 Copy of Bylaws, as amended through May 13, 1993. [Filed as Exhibit 3.01 to the Company's Form 10-Q for the quarter ended June 30, 1993, and incorporated by reference herein]
4.01 Copy of Trust Indenture dated November 1, 1949, from the Company to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to Registration Statement 2-8283 and incorporated by reference herein]
4.02 Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.05 to Registration Statement 2-9371 and incorporated by reference herein]
4.03 Copy of Supplemental Indenture dated February 1, 1954, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.03 to Registration Statement 2-11923 and incorporated by reference herein]
4.04 Copy of Supplemental Indenture dated September 1, 1957, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.04 to Registration Statement 2-17047 and incorporated by reference herein]
4.05 Copy of Supplemental Indenture dated October 1, 1960, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.05 to Registration Statement 2-24920 and incorporated by reference herein]
4.06 Copy of Supplemental Indenture dated June 1, 1966, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.06 to Registration Statement 2-28865 and incorporated by reference herein]
4.07 Copy of Supplemental Indenture dated June 1, 1968, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.07 to Registration Statement 2-37368 and incorporated by reference herein]
4.08 Copy of Supplemental Indenture dated June 1, 1970, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.08 to Registration Statement 2-37368 and incorporated by reference herein]
4.09 Copy of Supplemental Indenture dated August 1, 1971, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.09 to Registration Statement 2-44295 and incorporated by reference herein]
4.10 Copy of Supplemental Indenture dated June 1, 1972, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.10 to Registration Statement 2-52643 and incorporated by reference herein]
4.11 Copy of Supplemental Indenture dated February 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.11 to Registration Statement 2-57252 and incorporated by reference herein]
4.12 Copy of Supplemental Indenture dated September 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.12 to Registration Statement 2-57252 and incorporated by reference herein]
4.13 Copy of Supplemental Indenture dated September 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.13 to Registration Statement 2-57252 and incorporated by reference herein]
4.14 Copy of Supplemental Indenture dated October 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.14 to Registration Statement 2-65271 and incorporated by reference herein]
4.15 Copy of Supplemental Indenture dated June 1, 1978, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.15 to Registration Statement 2-65271 and incorporated by reference herein]
4.16 Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.16 to Registration Statement 2-65271 and incorporated by reference herein]
4.17 Copy of Supplemental Indenture dated September 1, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.18 Copy of Supplemental Indenture dated September 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.19 Copy of Supplemental Indenture dated September 15, 1981, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
4.20 Copy of Supplemental Indenture dated March 1, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.20 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.21 Copy of Supplemental Indenture dated March 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.22 Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.23 Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.23 to the Company's Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein]
4.24 Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein]
4.25 Copy of Supplemental Indenture dated November 15, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.26 Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.27 Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein]
4.28 Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.29 Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.30 Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.31 Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.32 Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.33 Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.34 Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.35 Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.36 Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.01 Copy of Agreement dated September 1, 1970, between Texas Gas Transmission Corporation and the Company covering the purchase of natural gas. [Filed as Exhibit 4.01 to Registration Statement 2-40985 and incorporated by reference herein]
10.02 Copies of Agreement between Sponsoring Companies re: Project D of Atomic Energy Commission, dated May 12, 1952, Memorandums of Understanding between Sponsoring Companies re: Project D of Atomic Energy Commission, dated September 19, 1952 and October 28, 1952, and Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission, dated October 15, 1952. [Filed as Exhibit 13(y) to Registration Statement 2-9975 and incorporated by reference herein]
10.03 Copy of Modification No. 1 dated July 23, 1953, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4.03(b) to Registration Statement 2-24920 and incorporated by reference herein]
10.04 Copy of Modification No. 2 dated March 15, 1964, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02c to Registration Statement 2-61607 and incorporated by reference herein]
10.05 Copy of Modification No. 3 and No. 4 dated May 12, 1966 and January 7, 1967, respectively, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibits 4(a)(13) and 4(a)(14) to Registration Statement 2-26063 and incorporated by reference herein]
10.06 Copy of Modification No. 5 dated August 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 13(c) to Registration Statement 2-27316 and incorporated by reference herein]
10.07 Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02f to Registration Statement 2-61607 and incorporated by reference herein]
10.08 Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to Registration Statement 2-26063 and incorporated by reference herein]
10.09 Copies of Amendments to Agreements (iii) and (iv) referred to under 10.07 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02h to Registration Statement 2-61607 and incorporated by reference herein]
10.10 Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02i to Registration Statement 2-61607 and incorporated by reference herein]
10.11 Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02j to Registration Statement 2-6l607 and incorporated by reference herein]
10.12 Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to Registration Statement 2-26063 and incorporated by reference herein]
10.13 Copy of Modification No. 6 dated November 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4(g) to Registration Statement 2-28524 and incorporated by reference herein]
10.14 Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02m to Registration Statement 2-37368 and incorporated by reference herein]
10.15 Copy of Modification No. 7 dated November 5, 1975, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02n to Registration Statement 2-56357 and incorporated by reference herein]
10.16 Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02o to Registration Statement 2-56357 and incorporated by reference herein]
10.17 Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02p to Registration Statement 2-6l607 and incorporated by reference herein]
10.18 Copy of Modification No. 8 dated June 23, 1977, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02q to Registration Statement 2-61607 and incorporated by reference herein]
10.19 Copy of Modification No. 9 dated July 1, 1978, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02r to Registration Statement 2-63149 and incorporated by reference herein]
10.20 Copy of Modification No. 10 dated August 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.21 Copy of Modification No. 11 dated September 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.22 Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.23 Copy of Modification No. 12 dated August 1, 1981, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.24 Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.25 Copy of Diversity Power Agreement dated September 9, 1987, between East Kentucky Power Cooperative and the Company covering the purchase and sale of power between the two companies from 1988 through 1995. [Filed as Exhibit 10.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein]
10.26 Copy of Supplemental Executive Retirement Plan as amended through January 3, 1990, covering all officers of the Company. [Filed as Exhibit 10.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein]
10.27 Copy of Omnibus Long-Term Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 4.01 to the Company's Registration Statement 33-38557 and incorporated by reference herein]
10.28 Copy of Key Employee Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 10.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein]
10.29 Copy of LG&E Energy Corp. Deferred Stock Compensation Plan effective January 1, 1992, covering non-employee directors of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein]
10.30 Copy of form of change in control agreement for officers of Louisville Gas and Electric Company. [Filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.31 Copy of Supplemental Executive Retirement Plan for Roger W. Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.32 Copy of Nonqualified Savings Plan covering officers of the Company, effective January 1, 1992. [Filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.33 Copy of Modification No. 13 dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.34 Copy of Modification No. 14 dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.35 Copy of Modification No. 7 dated January 15, 1992, to Inter- Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.36 Copy of Modification No. 15 dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.37 Firm Transportation Agreement, dated November 1, 1993, between Texas Gas Transmission Corporation and the Company covering the transmission of natural gas. [Filed as Exhibit 10.46 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.38 Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (8-year term) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (2-year term) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (5-year term) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.39 Employment Contract between LG&E Energy Corp. and Roger W. Hale effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.40 Copy of LG&E Energy Corp. Stock Option Plan for Non-Employee Directors. [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.41 Copy of Coal Supply Agreement dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal.
10.42 Copy of Amendment No. 1 dated January 1, 1991, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal
Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal.
10.43 Copy of Amendment No. 2 dated November 27, 1991, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal.
10.44 Copy of Amendment No. 3 dated January 1, 1994, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal.
10.45 Copy of Amendment No. 4 dated January 1, 1995, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal.
10.46 Copy of Coal Supply Agreement dated January 1, 1994, between Peabody Coalsales Company and the Company covering the purchase of coal.
12 Computation of Ratio of Earnings to Fixed Charges
23 Consent of Independent Public Accountants
24 Power of Attorney
27 Financial Data Schedule
(b) Executive Compensation Plans and Arrangements:
Supplemental Executive Retirement Plan as amended through January 3, 1990, covering all officers of the Company. [Filed as Exhibit 10.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein]
Omnibus Long-Term Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 4.01 to the Company's Registration Statement 33-38557 and incorporated by reference herein]
Key Employee Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 10.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein]
LG&E Energy Corp. Deferred Stock Compensation Plan effective January 1, 1992, covering non-employee directors of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein]
Form of change in control agreement for officers of Louisville Gas and Electric Company. [Filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
Supplemental Executive Retirement Plan for R. W. Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
Nonqualified Savings Plan covering officers of the Company effective January 1, 1992. [Filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
Employment Contract between LG&E Energy Corp. and Roger W. Hale effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
LG&E Energy Corp. Stock Option Plan for Non-Employee Directors. [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
(c) Reports on Form 8-K:
The Company was not required to file a Form 8-K report during the fourth quarter of 1994.
SCHEDULE II
LOUISVILLE GAS AND ELECTRIC COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 1994 (Thousands of $)
SIGNATURES
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.
LOUISVILLE GAS AND ELECTRIC COMPANY Registrant
March 24, 1995 By - -------------- ------------------------------------------ (Date) M. L. Fowler Vice President and Controller
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 date indicated.
Signature Title Date --------- ----- ----
ROGER W. HALE Chairman of the Board and Chief Executive Officer (Principal Executive Officer);
CHARLES A. MARKEL III Treasurer (Principal Financial Officer);
M. L. FOWLER Vice President and Controller (Principal Accounting Officer);
WILLIAM C. BALLARD, JR. Director;
OWSLEY BROWN II Director;
S. GORDON DABNEY Director;
GENE P. GARDNER Director;
J. DAVID GRISSOM Director;
DAVID B. LEWIS Director;
ANNE H. MCNAMARA Director;
T. BALLARD MORTON, JR. Director; and
DR. DONALD C. SWAIN Director.
By__________________________________ March 24, 1995 M. L. FOWLER (Attorney-In-Fact)