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 258,000 customers and electricity to approximately 336,000 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 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 (the "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. For a more detailed discussion of the proceedings relating to Trimble County Unit 1, see Note 8 of the Notes to Financial Statements under Item 8.
In February 1993, the Company sold a 12.88% ownership interest in the Unit to Indiana Municipal Power Agency, completing the Company's plan to sell the 25% not allowed for ratemaking. The Company had previously sold a 12.12% ownership interest in the Unit to the Illinois Municipal Electric Agency in 1991. See Note 9 of the Notes to Financial Statements, Jointly Owned Electric Utility Plant, under Item 8 for a further discussion. 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. 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 anticipates incurring capital expenditures during the next four years of approximately $40 million for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall 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 which 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 7 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 is responding to increased competition in a number of ways designed to lower its costs and increase sales.
One such response has been for the Company's parent, LG&E Energy Corp., to realign into new business units effective January 1, 1994. Under the realignment, Energy Corp. formed a national business unit, LG&E Energy Services, to develop and manage all of its utility and non-utility electric power generation and concentrate on the marketing and brokering of electric power on a regional and national basis. The realignment will allow the Company to increase its focus on customer service and to develop more customer options as the utility industry becomes more competitive. The realignment does not affect the regulation of the Company by the Commission. In addition to the realignment, the Company is re-evaluating its regulatory strategy to pursue full cost recovery of certain deferred expenses which are recorded as a regulatory asset. See Notes 1, 2, and 7 of Notes to Financial Statements under Item 8, for a discussion of these regulatory assets.
On May 24, 1993, the Federal Energy Regulatory Commission (FERC) gave final approval for a market-based rate tariff and two transmission service tariffs that were filed by the Company. The market-based rate tariff enables the Company to sell up to 75 Mw of firm generation capacity at market-based rates. It also enables the Company to sell an unlimited amount of non-firm power at market-based rates, as long as the power is from the Company's own generation resources. Under the two transmission service tariffs that were approved by FERC, utilities, independent power producers, and qualifying co-generation or small power production facilities may obtain firm or coordination transmission service from the Company. These tariffs provide open access to the Company's transmission system and enable parties requesting either type of transmission service to transmit wholesale power across the Company's system. However, service under these tariffs is not available to ultimate consumers of electric utility service.
In responding to competition in the gas distribution business, the Company has upgraded gas storage facilities and invested in new equipment. By using the 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 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, delays and uncertainties in the regulatory process and costs of compliance with environmental laws and regulations.
For the year ended December 31, 1993, 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:
(Thousands of $) ----------------------------- Electric Gas Combined % Combined -------- --- -------- ---------- Residential................. $195,273 $112,508 $307,781 44% Commercial.................. 154,337 43,568 197,905 28 Industrial.................. 104,506 28,310 132,816 19 Public authorities.......... 52,183 13,846 66,029 9 ------- ------- ------- --- Total-ultimate consumers.. 506,299 198,232 704,531 100% --- --- Other utilities............. 58,959 - 58,959 Gas transportation-net...... - 5,147 5,147 Miscellaneous............... 4,952 1,536 6,488 ------- ------- ------- Total.................... $570,210 $204,915 $775,125 ------- ------- ------- ------- ------- -------
See Note 10 of the Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 1993. Electric Operations
The sources of electric operating revenues and the volumes of sales for the three years ended December 31, 1993, were as follows:
1993 1992 1991 ---- ---- ---- ELECTRIC OPERATING REVENUES (Thousands of $): Residential........................ $195,273 $174,559 $193,923 Small commercial and industrial.... 70,106 66,183 68,332 Large commercial................... 84,231 80,041 81,171 Large industrial................... 104,506 101,699 102,558 Public authorities................. 52,183 49,599 51,390 ------- ------- ------- Total-ultimate consumers.......... 506,299 472,081 497,374 Other electric utilities........... 58,959 45,698 40,745 Miscellaneous...................... 4,952 3,890 4,296 ------- ------- ------- Total............................. $570,210 $521,669 $542,415 ------- ------- ------- ------- ------- -------
ELECTRIC SALES (Thousands of kwh): Residential.......................... 3,230,463 2,923,517 3,229,153 Small commercial and industrial...... 1,056,977 1,010,830 1,042,543 Large commercial..................... 1,696,686 1,624,441 1,650,894 Large industrial..................... 2,736,269 2,671,212 2,625,915 Public authorities................... 1,053,928 1,004,911 1,046,035 ---------- ---------- ---------- Total-ultimate consumers............ 9,774,323 9,234,911 9,594,540 Other electric utilities............. 3,299,510 3,234,758 2,476,921 ---------- ---------- ---------- Total............................... 13,073,833 12,469,669 12,071,461 ---------- ---------- ---------- ---------- ---------- ----------
At December 31, 1993, the Company had 336,124 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 1993 was approximately .78 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 Fahrenheit (average for the day was 84 degrees Fahrenheit). 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 reliability criterion for generation capacity planning is to provide a minimum reserve margin of 18%. At February 28, 1994, 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 and East Kentucky have an agreement that allows East Kentucky to purchase power during its peak season, that period during which the utility's customers use the greatest amount of power, and the Company to sell power during its off-peak season. The agreement entitles East Kentucky to buy from the Company 30 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 $65 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, 1993, were as follows:
1993 1992 1991 ---- ---- ---- GAS OPERATING REVENUES (Thousands of $): Residential........................ $112,508 $ 96,175 $ 92,142 Commercial......................... 43,568 36,801 34,913 Industrial......................... 28,310 26,156 18,683 Public authorities................. 13,846 13,884 13,107 ------- ------- ------- Total-ultimate consumers.......... 198,232 173,016 158,845 Gas transportation-net............. 5,147 4,169 5,886 Miscellaneous...................... 1,536 1,341 1,560 ------- ------- ------- Total............................. $204,915 $178,526 $166,291 ------- ------- ------- ------- ------- -------
GAS SALES (Millions of cu. ft.): Residential........................ 24,330 22,465 21,795 Commercial......................... 10,308 9,527 9,160 Industrial......................... 7,817 8,077 5,945 Public authorities................. 3,515 3,864 3,721 ------- ------- ------- Total-ultimate consumers.......... 45,970 43,933 40,621 Gas transported.................... 5,249 4,155 6,231 ------- ------- ------- Total............................. 51,219 48,088 46,852 ------- ------- ------- ------- ------- -------
At December 31, 1993, the Company had 258,185 gas customers.
The Company has extensive 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 producers or brokers for delivery through the Company's distribution system. 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. The 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 Fahrenheit. During 1993, the maximum day gas sendout was 447,000 Mcf, occurring on February 18, when the average temperature for the day was 11 degrees Fahrenheit. Supply on that day consisted of 171,000 Mcf from purchases, 238,000 Mcf delivered from underground storage, and 38,000 Mcf transported for industrial customers. For further discussion, see Gas Supply. On November 1, 1993, the Company began purchasing and transporting its natural gas supplies under the new requirements created by FERC Order No. 636 which was issued in 1992. 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 several other sources.
Throughout 1993, the Company undertook a review to evaluate and select the pipeline services and gas supplies needed. As a result of this review, the Company entered into several distinct transportation and purchase agreements. The Company should benefit from FERC Order No. 636 through enhanced access to competitively priced natural gas supplies as well as more flexible transportation services. The Company has made the necessary modifications to its operations and to its gas supply clause to reflect these Order No. 636 changes. (For further discussion see Gas Supply.)
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 the most recent rate order of the Kentucky Commission, see Rates and Regulation under Item 7 and Note 8 of the 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. In November 1993, the Commission approved a comprehensive agreement on demand side management (DSM) programs. The agreement 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.
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, 1993, the Company's embedded cost of long-term debt was 6.4% and its ratio of earnings to fixed charges was 3.87. See Exhibit 12. For a further discussion of construction expenditures and financing, see Construction Expenditures and Capitalization and Liquidity under Item 7.
During the five years ended December 31, 1993, gross property additions amounted to $580 million. Funds for about 97% of these gross additions were generated internally. The gross additions during this period amounted to approximately 24% of total utility plant at December 31, 1993, and consisted of $480 million for electric properties and $100 million for gas properties. Gross retirements during the same period were $40 million, consisting of $29 million for electric properties and $11 million for gas properties. Coal Supply
Ninety percent 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.
In 1992, the Company entered into coal supply agreements with various suppliers for coal deliveries for 1993 and beyond. The Company normally augments its coal supply agreements with spot market purchases which, during 1993, 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, 1993, a coal inventory of approximately 433,000 tons, or a 28 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:
1993 1992 1991 ---- ---- ----
Per ton.............................. $26.58 $25.17 $24.51 Per million Btu...................... 1.14 1.09 1.06
Gas Supply
During 1993, the Company continued to purchase natural gas from and transport other natural gas supplies through Texas Gas at rates and terms regulated by the FERC. The Company also continued purchasing a portion of its natural gas supplies on the spot-market and transporting those supplies under various transportation agreements with Texas Gas pursuant to applicable FERC-approved tariffs. The Company received standby service from Texas Gas until its implementation of FERC Order No. 636. 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, 1997. 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 2, 5, and 8 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.
Contemporaneously with the conclusion of its transportation arrangements with Texas Gas, the Company 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 formerly supplied by the pipeline.
During 1994, the Company will be participating in several regulatory proceedings at FERC. Particularly, 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 recovered as a gas cost through the Company's purchased gas adjustment.
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 1992-1993 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 $2.91 in 1993, $2.77 in 1992, and $2.39 in 1991. Although upcoming regulatory changes may alter the ways in which the Company contracts for natural gas supplies, it is expected that the Company will continue to have adequate access to natural gas supplies at market sensitive prices. 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 1993, expenditures for pollution control facilities represented $128 million or 22% of total construction expenditures. The cost of operating and maintaining these facilities amounted to $22 million in both 1993 and 1992. The Company's anticipated capital expenditures for 1994 to comply with environmental laws are approximately $22 million. See Item 3 and Note 7 of Notes to Financial Statements under Item 8 for a discussion of specific environmental proceedings affecting the Company.
Labor Relations
The Company's 1,652 operating, maintenance and construction employees are members of the International Brotherhood of Electrical Workers (IBEW) Local 2100. On May 31, 1992, the IBEW voted to ratify a new three-year collective bargaining agreement. The new agreement became effective in November 1992 and will expire in November 1995.
Employees
The Company had 2,749 full-time employees at December 31, 1993. During the last quarter of 1993 and early 1994, the Company eliminated a number of full-time positions, and made early retirement available to a number of other employees. See Note 2 of Notes to Financial Statements under Item 8 for a further discussion of this matter. ITEM 2.


ITEM 2. Properties. - --------------------
At February 28, 1994, the Company owned and operated the following electric generating stations:
Year in Steam Stations: Service Capability Rating (Kw) ------- ---------------------- Mill Creek-Kosmosdale, Ky. Unit 1.......................... 1972 303,000 Unit 2.......................... 1974 301,000 Unit 3.......................... 1978 386,000 Unit 4.......................... 1982 466,000 1,456,000 ------- Cane Run-near Louisville, Ky. Unit 3.......................... 1958 115,000 Unit 4.......................... 1962 155,000 Unit 5.......................... 1966 168,000 Unit 6.......................... 1969 240,000 678,000 ------- Trimble County-Bedford, Ky. Unit 1.......................... 1990 371,000 (1)
Combustion Turbine Generators (Peaking capability): Zorn............................ 1969 16,000 Paddy's Run..................... 1968 43,000 Cane Run........................ 1968 16,000 Waterside....................... 1964 33,000 108,000 ------- --------- 2,613,000 --------- ---------
(1) Amount shown represents the Company's 75% interest in the Unit. See Note 9 of the Notes to Financial Statements, Jointly Owned Electric Utility Plant, under Item 8 for a discussion of the sale of 25% of the Unit to IMEA and IMPA. The Company is responsible for operation of the Unit and is reimbursed by IMEA and IMPA for expenditures related to the Unit based on their proportionate share of ownership interest.
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, 1993, the Company's electric transmission system included 20 substations with a total capacity of approximately 10,518,897 Kva and approximately 645 structure miles of lines. The electric distribution system included 84 substations with a total capacity of approximately 2,948,768 Kva, 3,499 structure miles of overhead lines, 231 miles of underground conduit, and 5,170 miles of underground conductors. The Company's gas transmission system includes 177 miles of transmission mains, and the gas distribution system includes 3,226 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. - ---------------------------
Rate Case and Trimble County Station
For a discussion of the most recent rate order of the Public Service Commission of Kentucky and a detailed discussion of the orders of the Kentucky Commission and rulings of the Franklin Circuit Court and the Kentucky Court of Appeals concerning Trimble County Unit 1, see Item 7 and Note 8 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 (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 in the process of reviewing the Company's plan, and is not expected to issue its report and recommendations concerning the plan until late 1994 at the earliest. The Kentucky Commission's regulations do not require it to hold any hearings or issue any formal orders regarding the Plan. Environmental
The Clean Air Act Amendments of 1990 impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. This legislation is extremely complex and its effect will substantially depend on regulations issued by the U.S. Environmental Protection Agency. While the Company will incur some capital expenditures to comply with the Act's requirements, the overall impact of the Act on the Company is expected to be minimal. The Company is closely monitoring the continuing rule-making process in order to assess the precise impact of the legislation on the Company.
For a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run generating plants, manufacturing gas plant sites, and certain other environmental issues, see Note 7 of the Notes to Financial Statements under Item 8.
Based upon prior precedents established by the Kentucky Commission and the Environmental Cost Recovery legislation, the Company expects to have an opportunity to recover through future ratemaking proceedings, its costs associated with remedial measures required to comply with environmental laws and regulations.
Other
The Company is a defendant in lawsuits seeking compensatory and, in certain instances, punitive damages for injuries purportedly incurred by individuals coming into contact with the Company's electric or gas facilities and/or services. 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. ITEM 4.
ITEM 4. Submission of Matters to a Vote of Security Holders. - -------------------------------------------------------------
None
Executive Officers of the Company.
Effective Date of Election Name Age Position to Present Position - ---- --- -------- --------------------------
Roger W. Hale 50 Chairman of the Board and Chief Executive Officer January 1, 1992
Victor A. Staffieri 38 President January 1, 1994
David R. Carey 40 Senior Vice President, Operations January 1, 1994
Raymond A. Bennett 60 Vice President, Gas Service Business January 1, 1994
M. Lee Fowler 57 Vice President and Controller September 1, 1988
Wendy C. Heck 40 Vice President, Information Services January 1, 1994
Chris Hermann 46 Vice President and General Manager, Wholesale Electric Business January 1, 1993
Charles A. Markel III 46 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 May 24, 1994.
There are no family relationships between executive officers of the Company.
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, 1989: Ms. Heck was Manager-Internal Audit prior to January 1990, Vice President-Internal Auditing prior to January 1, 1992, Vice President-Fuels and Operating Services prior to January 1, 1993, and Vice President-Fuels and Information Services thereafter; Mr. Hermann was Manager-Administration, Power Production prior to November 1989, General Manager-Power Production prior to January 1992 and General Manager-Wholesale Electric thereafter; Mr. Markel was Vice President and Treasurer prior to March 1, 1990, Vice President-Finance and Treasurer prior to January 1, 1992, and Senior Vice President and Chief Financial Officer thereafter. Effective January 1, 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. Hale was Chairman of the Board, President and Chief Executive Officer of the Company, and prior to February 1, 1990, President and Chief Executive Officer. Prior to June 1, 1989, Mr. Hale was employed by BellSouth Enterprises, Inc. and held the position of Executive Vice President.
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 15, 1992, Senior Vice President, General Counsel and Corporate Secretary. Prior to March 15, 1992, Mr. Staffieri was employed by Long Island Lighting Company and held the position of General Counsel and Secretary from April 1989 to March 1992, and Deputy General Counsel prior to April 1989.
Prior to election to his current position, Mr. Carey was Vice President and General Manager, Retail Electric Business of the Company, prior to January 1, 1993, Vice President-Marketing and General Manager, Electric Service, prior to January 1, 1992, Vice President-Marketing and Planning, and prior to July 14, 1990, Vice President-Marketing and Sales. Prior to January 1990, Mr. Carey was employed by AT&T General Business Systems and held the position of Director-Strategic and Business Planning.
Prior to election to his current position, Mr. Bennett was Vice President and General Manager, Gas Service Business of the Company, and prior to January 1, 1992, General Manager, Gas Operations. Prior to May 1990, Mr. Bennett was employed by the Railroad Commission of Texas and held the position of Director of Transportation-Gas Utility Division. 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:
1993 1992 ---- ---- (Thousands of $) First Quarter................................ $17,000 $16,000 Second Quarter............................... 16,500 16,000 Third Quarter................................ 16,500 17,000 Fourth Quarter............................... 17,000 17,500
ITEM 6.
ITEM 6. Selected Financial Data. - ---------------------------------
Years Ended December 31 (Thousands of $) ----------------------------------------------------- 1993 1992 1991 1990 1989 ---- ---- ---- ---- ----
Operating Revenues.... $775,125 $700,195 $708,706 $698,758 $686,996 Net Operating Income.. 136,118 125,829 142,730 137,717 127,560 Net Income............ 90,535 73,793 94,643 101,686 76,091 Net Income Available for Common Stock.... 84,554 66,620 85,179 92,221 66,625 Total Assets.......... 2,072,910 1,973,039 1,948,410 1,995,782 1,905,306 Long-Term Obligations (including amounts due within one year)............... 662,800 686,262 687,662 688,250 629,500
ITEM 7.
ITEM 7. Management's Discussion and Analysis of Results of Operations and Financial Condition. - --------------------------------------------------------------------------
OVERVIEW
The Company's financial condition improved during 1993. Net income increased $16.7 million or 23% over 1992 due primarily to higher electric sales which resulted from the warmer summer weather experienced in 1993. The Company also maintained its strong credit ratings throughout 1993. Effective January 1, 1994, the Company's parent, LG&E Energy Corp., announced a major realignment of its business units to reflect its outlook for rapidly emerging competition in all segments of the energy services industry. In addition to the organizational change implemented by the parent, the Company is presently re-evaluating its regulatory strategy to pursue full cost recovery of certain deferred expenses which the Company has recorded as regulatory assets. See Future Outlook for a further discussion of this matter.
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 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
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.
The decrease in earnings for 1992 from 1991 resulted primarily from decreased electric sales to residential customers as a result of the cooler summer weather experienced in 1992, the gain recognized in 1991 on the sale of a portion of the Trimble County plant to the Illinois Municipal Electric Agency (IMEA), higher depreciation and operation expenses and decreased interest earned on temporary cash investments. These decreases were partially offset by favorable financing activities and decreased maintenance expenses.
Rates and Regulation
The Company is subject to the jurisdiction of the Public Service Commission of Kentucky (Commission) in virtually all matters related to electric and gas utility regulation. The Company last filed for a rate increase with the Commission in June 1990 based on the test-year ended April 30, 1990. The request was for a general rate increase of $34.9 million ($31.0 million electric and $3.9 million gas). A final order was issued in September 1991 that effectively granted the Company an annual increase in rates of $6.8 million ($6.1 million electric and $.7 million gas). The Commission's order authorized a rate of return on common equity of 12.5%. On April 21, 1993, the Company, the Kentucky Attorney General, the Jefferson County Attorney, and representatives of several customer-interest groups filed with the Commission a request for approval of a comprehensive agreement on demand side management (DSM) programs. Under the agreement, the Company will commit up to $3.3 million over three years (from 1994 through 1996) for initial programs that include a residential energy conservation and education program and a commercial conservation audit program. Future programs will be developed through a formal collaborative process. The agreement contains a rate mechanism that will (1) provide the Company concurrent recovery of DSM program costs, (2) provide the Company an incentive for implementing DSM programs, and (3) allow the Company to recover revenues due to lost sales associated with the DSM programs. On November 12, 1993, the Commission approved the agreement.
Revenues from lost sales to residential customers are collected through a "decoupling mechanism". The Company's residential decoupling mechanism breaks the link between the level of the Company's residential kilowatt-hour and Mcf sales and its non-fuel revenues. Under traditional regulation, a utility's revenue varies with changes in its level of kilowatt-hour or Mcf sales. The residential decoupling mechanism will allow the Company to recover a predetermined level of revenue per customer based on the rate set in the Company's last rate case, which will not vary with the level of kilowatt-hour or Mcf sales. Residential revenues will be adjusted to reflect (1) changes in the number of residential customers and (2) a pre-established annual growth factor in residential revenue per customer. Decoupling, in effect, removes the impact on the Company's non-fuel revenues from changes in kilowatt-hour or Mcf sales due to weather, fluctuations in the economy, and conservation efforts. Under this mechanism, if actual sales produce lower revenues than are produced by the predetermined per-customer amount, the difference is deferred for recovery from customers through an adjustment in rates over a period that will not exceed two years. Conversely, if actual sales produce more revenues than would be realized using the predetermined per-customer amount, the difference will be returned to customers through subsequent rate adjustments over a period not to exceed two years. Residential revenues reported in the financial statements for 1994 through 1996 will be determined in accordance with the agreed upon predetermined amount per-customer plus growth, and recovery of fuel and gas costs. The difference between the revenues shown in the financial statements and the amounts billed to customers will be recorded on the balance sheet and deferred for future recovery from or return to customers.
As more fully discussed in Note 8 of Notes to Financial Statements under Item 8, the Commission has set a procedural schedule to determine the appropriate ratemaking treatment to exclude 25% of the Trimble County plant from customer rates.
On May 24, 1993, the Federal Energy Regulatory Commission (FERC) gave final approval for a market-based rate tariff and two transmission service tariffs that were filed by the Company. This tariff enables the Company to sell up to 75 Mw of firm generation capacity at market-based rates. It also enables the Company to sell an unlimited amount of non-firm power at market- based rates, as long as the power is from the Company's own generation resources. Under the two transmission service tariffs that were approved by FERC, utilities, independent power producers, and qualifying co-generation or small power production facilities may obtain firm or coordination transmission service from the Company. These tariffs provide open access to the Company's transmission system and enable parties requesting either type of transmission service to transmit wholesale power across the Company's system. However, service under these tariffs is not available to ultimate consumers of electric utility service.
Revenues
A comparison of operating revenues for the years 1993 and 1992 with the immediately preceding years reflects both increases and decreases which have been segregated by the following principal causes (in thousands of $):
Increase (Decrease) From Prior Period ---------------------------------------- Electric Revenues Gas Revenues ------------------ ------------------- Cause 1993 1992 1993 1992 ----- ---- ---- ---- ----
Sales to Ultimate Consumers: Rate increases effective in 1991. $ - $ 748 $ - $ 173 Fuel and gas supply adjustments, etc............... 6,832 313 19,479 1,044 Variation in sales volumes....... 27,385 (26,354) 5,736 12,954 ------ ------ ------ ------ Total.......................... 34,217 (25,293) 25,215 14,171 Sales to other utilities........... 13,261 4,953 - - Gas transportation-net............. - - 978 (1,717) Other.............................. 1,063 (406) 196 (219) ------ ------ ------ ------- Total.......................... $48,541 $(20,746) $26,389 $12,235 ------ ------ ------ ------ ------ ------ ------ ------
Electric revenues increased in 1993 primarily because of the warmer summer weather. Sales of electricity to other utilities increased over 1992 levels due to the Company's aggressive efforts in marketing off-system sales of energy. The increase in gas sales for 1993 is largely attributable to cooler winter weather in the region and customer growth.
Expenses
Fuel for electric generation and gas supply expenses account for a large segment of the Company's total operating costs. The Company's electric and gas rates contain a fuel adjustment clause and a gas supply clause, respectively, whereby increases or decreases in the cost of fuel and gas supply may be reflected in the Company's rates, subject to the approval of the Commission. Fuel expenses increased in 1993 primarily because of an increase in generation and the higher cost of coal purchased. The average delivered cost per ton of coal purchased was $26.58 in 1993, $25.17 in 1992, and $24.51 in 1991.
The increase in power purchased expense reflects an increase in the quantity of power purchased mainly because of wheeling arrangements with other utilities.
Gas supply expenses increased in 1993 and 1992 largely because of an increase in both the cost and the volume of gas purchased. The average unit cost per Mcf of purchased gas was $2.91 in 1993, $2.77 in 1992, and $2.39 in 1991.
Other operation and maintenance expenses increased $7.4 million in 1993. This increase is primarily attributable to increased expenses for the operation and maintenance of electric generating plants and higher administrative and general costs. The increase in 1992 over 1991 resulted primarily from costs associated with legal settlements relating to personal injury claims and storm damage expenses. General increases in labor and material costs are also reflected in operation and maintenance expenses.
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 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 in February 1993. A decrease in 1992 from 1991 resulted primarily from a $4.2 million after-tax gain recorded in 1991 on the sale of a 12.12% ownership interest in Trimble County to IMEA and decreased interest income of $1.1 million from temporary cash investments.
Interest charges decreased in 1993 and 1992 primarily because of an aggressive program to refinance at lower interest rates. The Company refinanced approximately $205 million of its outstanding debt in 1993. The embedded cost of long-term debt at December 31, 1993, was 6.4%; at December 31, 1992, 7.0%.
Preferred dividends reflect the lower dividend rates that resulted from the Company's refunding of the $25 million, $8.90 Series with a $5.875 Series in May 1993. In February 1992, the Company refunded the $8.72 and $9.54 Series with $50 million of Auction Rate Series. The weighted average preferred dividend rate at December 31, 1993, was 4.72%; at December 31, 1992, 5.36%.
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. Reference is made to Note 2 of Notes to Financial Statements under Item 8

Item 8. Financial Statements and Supplementary Data - ---------------------------------------------------
LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Thousands of $)
Years Ended December 31 ------------------------------ 1993 1992 1991 ---- ---- ----
Operating Revenues Electric................................. $570,210 $521,669 $542,415 Gas...................................... 204,915 178,526 166,291 ------- ------- ------- Total operating revenues (Note 1)...... 775,125 700,195 708,706 ------- ------- ------- Operating Expenses Fuel for electric generation............. 149,436 132,551 132,392 Power purchased.......................... 17,228 12,044 11,478 Gas supply expenses...................... 139,054 115,521 104,212 Other operation expenses................. 136,693 130,740 126,842 Maintenance.............................. 48,414 46,931 49,079 Depreciation and amortization............ 79,655 76,903 73,273 Federal and State income taxes (Note 3)......................... 52,334 43,840 53,195 Property and other taxes................. 16,193 15,836 15,505 ------- ------- ------- Total operating expenses............... 639,007 574,366 565,976 ------- ------- ------- Net Operating Income....................... 136,118 125,829 142,730 Other Income and (Deductions).............. 1,913 (2,203) 4,593 ------- ------- ------- Income before Interest Charges............. 138,031 123,626 147,323 Interest Charges........................... 47,496 49,833 52,680 ------- ------- -------
Net Income................................. 90,535 73,793 94,643 Preferred Stock Dividends.................. 5,981 7,173 9,464 ------- ------- ------- Net Income Available for Common Stock...... $ 84,554 $ 66,620 $ 85,179 ------- ------- ------- ------- ------- -------
The accompanying notes are an integral part of these financial statements. LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF RETAINED EARNINGS (Thousands of $)
Years Ended December 31 ------------------------------ 1993 1992 1991 ---- ---- ----
Balance January 1.......................... $178,667 $181,694 $219,515 Add net income............................. 90,535 73,793 94,643 ------- ------- ------- 269,202 255,487 314,158 ------- ------- -------
Deduct: Cash dividends declared on stock: 5% cumulative preferred........... 1,075 1,076 1,076 7.45% cumulative preferred........ 1,598 1,598 1,598 $8.72 cumulative preferred........ - 454 2,180 $8.90 cumulative preferred........ 1,113 2,225 2,225 $9.54 cumulative preferred........ - 497 2,385 Auction rate cumulative preferred. 1,322 1,323 - $5.875 cumulative preferred....... 873 - - Common............................ 67,500 67,500 123,000 Preferred stock redemption expense. 818 2,147 - ------- ------- ------- 74,299 76,820 132,464 ------- ------- -------
Balance December 31........................ $194,903 $178,667 $181,694 ------- ------- ------- ------- ------- -------
The accompanying notes are an integral part of these financial statements. LOUISVILLE GAS AND ELECTRIC COMPANY BALANCE SHEETS (Thousands of $)
ASSETS
December 31 ----------------------------- 1993 1992 ---- ---- Utility Plant, at original cost Electric................................... $2,019,139 $1,976,206 Gas........................................ 260,485 240,818 Common..................................... 132,692 121,105 --------- --------- 2,412,316 2,338,129 Less: Reserve for depreciation............ 823,141 754,429 --------- --------- 1,589,175 1,583,700 Construction work in progress.............. 51,785 35,367 --------- --------- 1,640,960 1,619,067 --------- --------- Other Property and Investments - less reserve (Note 1)...................... 22,067 98,832 --------- --------- Current Assets Cash and temporary cash investments........ 44,105 946 Accounts receivable - less reserve of $1,474 in 1993 and $1,109 in 1992........ 104,397 92,719 Materials and supplies - at average cost Fuel (predominantly coal)................ 12,075 21,360 Gas stored underground................... 33,370 34,079 Other.................................... 40,357 41,034 Prepayments................................ 360 467 --------- --------- 234,664 190,605 --------- --------- Deferred Debits and Other Assets Unamortized debt expense................... 24,698 17,282 Accumulated deferred income taxes (Notes 1 and 3)................................... 58,675 12,179 Regulatory asset-income taxes (Note 1)..... 39,651 - Other...................................... 52,195 35,074 --------- --------- 175,219 64,535 --------- --------- $2,072,910 $1,973,039 --------- --------- --------- ---------
The accompanying notes are an integral part of these financial statements. LOUISVILLE GAS AND ELECTRIC COMPANY CAPITAL AND LIABILITIES (Thousands of $)
December 31 ----------------------------- 1993 1992 ---- ---- Capitalization (see Statements of Capitalization) Common equity.............................. $ 619,237 $ 603,001 Cumulative preferred stock................. 116,716 116,740 Long-term debt............................. 662,879 686,119 --------- --------- 1,398,832 1,405,860 --------- --------- Current Liabilities Long-term debt due within one year......... - 400 Notes payable (Note 6)..................... - 8,000 Accounts payable........................... 93,551 72,452 Dividends declared......................... 18,878 18,522 Accrued taxes.............................. 9,494 7,151 Accrued interest........................... 12,864 12,107 Other...................................... 11,127 11,494 --------- --------- 145,914 130,126 --------- ---------
Deferred Credits and Other Credits Accumulated deferred income taxes (Notes 1 and 3)................................... 340,235 295,677 Investment tax credit, in process of amortization............... 91,572 104,623 Customers' advances for construction....... 7,384 6,849 Regulatory liability-income taxes (Note 1). 46,528 - Other...................................... 42,445 29,904 --------- --------- 528,164 437,053 --------- --------- Commitments and Contingencies (Notes 7 and 8) $2,072,910 $1,973,039 --------- --------- --------- ---------
The accompanying notes are an integral part of these financial statements. LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Thousands of $)
Years Ended December 31 -------------------------------- 1993 1992 1991 ---- ---- ----
Cash Flows from Operating Activities Net income............................. $ 90,535 $ 73,793 $ 94,643 Items not requiring cash currently: Depreciation and amortization........ 79,887 79,686 76,431 Deferred income taxes - net.......... 4,938 28,911 23,292 Investment tax credit - net.......... (7,821) (5,033) (11,472) Gain on sale of capital asset........ (3,869) - (7,908) Other................................ 5,877 3,768 3,548 (Increase) decrease in certain net current assets: Accounts receivable.................. (11,678) (7,494) (4,629) Materials and supplies............... 10,671 (8,014) 5,390 Accounts payable..................... 21,099 4,546 (2,963) Accrued taxes........................ 2,343 1,967 (6,353) Accrued interest..................... 757 (1,716) 471 Prepayments and other................ (260) 538 71 Other.................................. (15,587) (11,321) (1,928) ------- ------- ------- Net cash provided from operating activities............... 176,892 159,631 168,593 ------- ------- ------- Cash Flows from Investing Activities Sale of capital asset.................. 91,076 - 94,164 Long-term investment in securities..... (11,097) (10,441) - Construction expenditures.............. (98,787) (101,175) (88,052) ------- ------- ------- Net cash provided from (used for) investing activities............... (18,808) (111,616) 6,112 ------- ------- -------
Cash Flows from Financing Activities Issuance of preferred stock............ 24,716 49,099 - Issuance of first mortgage bonds and pollution control bonds.............. 198,918 88,462 4,233 Redemption of preferred stock.......... (25,558) (51,443) - Retirement of first mortgage bonds and pollution control bonds.......... (231,876) (92,400) (5,088) Decrease in notes payable.............. (8,000) (4,000) (13,000) Payment of dividends................... (73,125) (74,517) (131,662) ------- ------- ------- Net cash used for financing activities......................... (114,925) (84,799) (145,517) ------- ------- -------
The accompanying notes are an integral part of these financial statements. LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Thousands of $)
Years Ended December 31 -------------------------------- 1993 1992 1991 ---- ---- ----
Net Increase (Decrease) in Cash and Temporary Cash Investments............. $ 43,159 $(36,784) $ 29,188
Cash and Temporary Cash Investments at Beginning of Year...................... 946 37,730 8,542 ------- ------- ------- Cash and Temporary Cash Investments at End of Year............................ $ 44,105 $ 946 $ 37,730 ------- ------- ------- ------- ------- -------
Supplemental Disclosures of Cash Flow Information Cash paid during the year for: Income taxes......................... $ 54,686 $ 19,741 $ 46,481 Interest on borrowed money........... 45,360 50,508 50,744
The accompanying notes are an integral part of these financial statements. LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Thousands of $)
December 31 ----------------------------- 1993 1992 ---- ----
Common Equity Common stock, without par value - Authorized 75,000,000 shares, outstanding 21,294,223 shares........... $ 425,170 $ 425,170 Common stock expense...................... (836) (836) Retained earnings......................... 194,903 178,667 --------- --------- $ 619,237 $ 603,001 --------- --------- Cumulative Preferred Stock (Note 4) Redeemable on 30 days notice by the Company
Shares Current Outstanding Redemption Price ----------- ---------------- $25 par value, 1,720,000 shares authorized - 5% series........ 860,287 $ 28.00 $ 21,507 $ 21,507 7.45% series..... 858,128 25.75 21,453 21,453
Without par value, 6,750,000 shares authorized - $8.90 series..... - - - 25,000 Auction Rate..... 500,000 100.00 50,000 50,000 $5.875 series.... 250,000 Not Redeemable 25,000 - Preferred stock expense..................... (1,244) (1,220) --------- --------- $ 116,716 $ 116,740 --------- ---------
The accompanying notes are an integral part of these financial statements. LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Thousands of $)
December 31 ----------------------------- 1993 1992 ---- ----
Long-Term Debt (Note 5) First mortgage bonds - Series due June 1, 1996, 5 5/8%......... $ 16,000 $ 16,000 Series due June 1, 1998, 6 3/4%......... 20,000 20,000 Series due August 1, 2001, 8 1/4%....... - 19,700 Series due July 1, 2002, 7 1/2%......... 20,000 20,000 Series due August 15, 2003, 6%.......... 42,600 - Series due November 1, 2006, 8 1/2%..... - 21,362 Pollution control series: B due September 1, 2006, 6 1/8%....... - 35,200 C due June 1, 1998, 6 1/8%............ - 7,000 C due June 1, 2008, 6 3/8%............ - 35,000 D due October 1, 2004, 6.6%........... - 20,000 D due October 1, 2009, 6.7%........... - 40,000 I due February 15, 2011, 9 3/4%....... - 26,000 J due July 1, 2015, 9 1/4%............ 40,000 40,000 K due December 1, 2016, 7 1/4%........ 27,500 27,500 L due December 1, 2016, 7 1/4%........ 22,500 22,500 N due February 1, 2019, 7 3/4%........ 35,000 35,000 O due February 1, 2019, 7 3/4%........ 35,000 35,000 P due June 15, 2015, 7.45%............ 25,000 25,000 Q due November 1, 2020, 7 5/8%........ 83,335 100,000 R due November 1, 2020, 6.55%......... 41,665 50,000 S due September 1, 2017, variable..... 31,000 31,000 T due September 1, 2017, variable..... 60,000 60,000 U due August 15, 2013, variable....... 35,200 - V due August 15, 2019, 5 5/8%......... 102,000 - W due October 15, 2020, 5.45%......... 26,000 - --------- --------- Total bonds outstanding................. 662,800 686,262 Less long-term debt due within one year. - 400 --------- --------- Long-term first mortgage bonds.......... 662,800 685,862 Unamortized premium on bonds.............. 79 257 --------- --------- 662,879 686,119 --------- --------- Total Capitalization........................ $1,398,832 $1,405,860 --------- --------- --------- ---------
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. All of the Company's Common Stock is held by LG&E Energy Corp.
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 Public Service Commission of Kentucky (Commission). The Company is subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. The Company has recorded certain regulatory assets at December 31, 1993, totaling approximately $31 million. See Note 2, Post-Retirement Benefits and Early Retirement/Work Force Reduction, and Note 7, Environmental, for a discussion of these regulatory assets. See Future Outlook under Item 7, Management's Discussion and Analysis, for a discussion of the Company's re-evaluation of its current regulatory strategy in regards to these assets.
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.
In December 1990, the 25% portion of the construction costs of the Trimble County Generating Station (Trimble County), which the Commission disallowed in setting customer rates, was reclassified from the Utility Plant section on the balance sheet to Other Property and Investments. In February 1991, the Company sold a 12.12% undivided interest in Trimble County to the Illinois Municipal Electric Agency (IMEA). In February 1993, the remaining 12.88% of Trimble County not allowed in rates was sold to the Indiana Municipal Power Agency (IMPA). See Notes 8 and 9, Trimble County Generating Plant and Jointly Owned Electric Utility Plant, respectively, for a further discussion. Depreciation. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for 1993 were approximately 3.3% (3.2% electric, 3.2% gas, and 5% common); for 1992, 3.3% (3.2% electric, 3.2% gas, and 5.4% common); and for 1991, 3.3% (3.2% electric, 3% gas, and 6.3% 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 (SFAS) No. 109, Accounting for Income Taxes, effective January 1, 1993. SFAS No. 109 adopts the liability method of accounting for income taxes, requiring deferred income tax assets and liabilities to be computed using tax rates that will be in effect when the book and tax temporary differences reverse. For the Company, the change in tax rates applied to accumulated deferred income taxes was not immediately recognized in operating results because of ratemaking treatment. At December 31, 1993, the deferred tax asset, which resulted primarily from unamortized investment tax credits, amounted to approximately $47 million. The deferred tax liability, which resulted primarily from book/tax utility property basis differences, totaled approximately $40 million. Regulatory assets and liabilities were established to recognize the future revenue requirement impact from these deferred taxes. The adoption of SFAS No. 109 did not have a material impact on the results of operations or financial position. The deferred tax balances and related regulatory assets and liabilities have been adjusted to reflect the increase in the corporate income tax rate from 34% to 35%.
Investment Tax Credits. Investment tax credits resulted from provisions of the tax law which 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. See Management's Discussion and Analysis, Rates and Regulation, under Item 7, for changes in recording residential revenues effective January 1, 1994.
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. Revenues and Customer Receivables. The Company is an operating public utility that supplies natural gas to approximately 258,000 customers and electricity to approximately 336,000 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, 1993, 74% of total operating revenues was derived from electric operations and 26% from gas operations.
Fair Value of Financial Instruments. Pursuant to the Financial Accounting Standards Board SFAS No. 107, Disclosures about Fair Value of Financial Instruments, the Company is required to disclose the fair value of financial instruments where practicable.
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 cost and estimated fair value of the Company's financial instruments as of December 31, 1993 and 1992, are as follows (in thousands of $):
1993 1992 ------------------ ------------------ Fair Fair Cost Value Cost Value ---- ----- ---- ----- Long-term investments: Practicable to estimate fair value................. $ 21,538 $ 21,538 $ 10,441 $ 10,441 Not practicable.............. 490 490 557 557 Preferred stock subject to mandatory redemption......... 25,000 24,750 - - Long-term debt................. 662,800 706,078 686,262 726,801
Note 2 - 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 cost was $2,669,000 for 1993, $2,598,000 for 1992, and $2,245,000 for 1991, of which approximately $425,000, $241,000, and $306,000, respectively, were charged to construction. The components of periodic pension expense are shown below (in thousands of $):
1993 1992 1991 ---- ---- ---- Service cost-benefits earned during the period.................. $ 4,516 $ 5,459 $ 4,098 Interest cost on projected benefit obligation................. 12,117 11,006 9,340 Actual return on plan assets......... (13,602) (8,850) (26,805) Amortization of transition asset..... (1,112) (1,076) (1,076) Net amortization and deferral........ 750 (3,941) 16,688 ------ ------ ------ Net pension cost..................... $ 2,669 $ 2,598 $ 2,245 ------ ------ ------ ------ ------ ------
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 $):
1993 1992 ---- ----
Actuarial present value of accumulated plan benefits: Vested.............................................. $137,655 $102,980 Non-Vested.......................................... 17,158 12,900 ------- -------
Accumulated benefit obligation...................... 154,813 115,880 Effect of projected future compensation............. 25,234 31,336 ------- ------- Projected benefit obligation........................ 180,047 147,216 Plan assets at fair value........................... 165,088 155,937 ------- ------- Plan assets (less than) in excess of projected benefit obligation...................... (14,959) 8,721 Unrecognized net transition asset................... (13,636) (14,403) Unrecognized prior service cost..................... 28,671 25,863 Unrecognized net gain............................... (23,860) (41,703) ------- -------
Accrued pension liability............................. $(23,784) $(21,522) ------- ------- ------- -------
The projected benefit obligation was determined using an assumed discount rate of 7.5% for 1993 and 8.5% for 1992. An assumed annual rate of increase in future compensation levels ranged from 3.5% to 4.5% for 1993 and 3.5% to 6.5% for 1992. The assumed long-term rate of return on plan assets was 8.5% for both periods. 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) 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. Beginning in 1993, the Company began to account for post-retirement benefits according to the provisions of SFAS No. 106.
The Company, based on an order from the Commission, has created a regulatory asset and is deferring the level of SFAS No. 106 expense in excess of the previous level of pay-as-you-go expense. The Commission's generic order stated that the proper level of expense for SFAS No. 106 would be determined in each utility's next general rate case.
The components of the net periodic post-retirement benefit cost for 1993 as calculated under SFAS No. 106 are as follows (in thousands of $):
Service cost .............................................. $ 701 Interest cost.............................................. 2,614 Amortization of transition obligation...................... 1,395 ------
Post-retirement benefit cost............................... $ 4,710 ------ ------
The accumulated post-retirement benefit obligation as calculated under SFAS No. 106 at December 31, 1993, is shown below (in thousands of $):
Retirees................................................... $(17,826) Fully eligible active employees............................ (4,001) Other active employees..................................... (15,945) ------
Accumulated post-retirement benefit obligation............. (37,772) Unrecognized net loss...................................... 4,966 Unrecognized transition obligation......................... 26,508 Previously recognized amount............................... 3,696 ------
Accrued post-retirement benefit liability.................. $ (2,602) ------ ------
The annual service cost was calculated using an assumed discount rate of 8.5% at January 1, 1993, and 7.5% at December 31, 1993. A medical cost increase factor that ranged between 6% and 11% was also used. A 1% increase in the health care cost trend rate would increase the Accumulated Post-Retirement Benefit Obligation by approximately $1.8 million and the annual service and interest cost by approximately $200,000. No funding has been established by the Company for post-retirement benefits.
Post-Employment Benefits. The Financial Accounting Standards Board issued SFAS No. 112, Employers' Accounting for Post-Employment Benefits, which requires the accrual of the expected cost of benefits to former or inactive employees after employment but before retirement. The Company adopted the new standard effective January 1, 1994, as required. Adoption of SFAS No. 112 will not have a material adverse impact on the financial position or results of operation of the Company.
Early Retirement/Work Force Reduction. During the last quarter of 1993 and early 1994, the Company eliminated approximately 350 full-time positions. The cost of the employee reduction program, approximately $11.5 million, consists primarily of separation payments, enhanced early retirement benefits, and health care benefits.
In 1992, an early retirement program was made available to all the 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 post-retirement 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 $1,795,000 for 1993, $767,000 for 1992, and $584,000 for 1991. The increase in 1993 401(k) expenses is due to the expansion of the program to the Company's union employees. Note 3 - Federal and State Income Taxes - ---------------------------------------
Components of income tax expense are shown in the table below (in thousands of $):
1993 1992 1991 ---- ---- ----
Included in Operating: Current - Federal.................... $31,082 $20,756 $33,727 - State...................... 8,920 6,354 8,126 Deferred - Federal-net................ 13,185 15,771 16,642 - State-net.................. 3,933 5,774 5,939 Deferred investment tax credit........ - - (6,385) Amortization of investment tax credit. (4,786) (4,815) (4,854) ------ ------ ------
Total............................... $52,334 $43,840 $53,195 ------ ------ ------
Included in Other Income and (Deductions): Current - Federal.................... $11,009 $(6,971) $ 1,763 - State...................... 4,034 (3,214) 299 Deferred - Federal-net................ (8,473) 4,670 565 - State-net.................. (3,707) 2,696 146 Deferred investment tax credit........ - 390 26 Amortization of investment tax credit. (3,035) (608) (259) ------ ------ ------
Total............................... $ (172) $(3,037) $ 2,540 ------ ------ ------
Total Income Tax Expense................ $52,162 $40,803 $55,735 ------ ------ ------ ------ ------ ------
Variations in the 1993 income tax expense from 1992 and 1991 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.
Provisions for deferred income taxes consist of the tax effects of the following temporary differences (in thousands of $):
1993 1992 1991 ---- ---- ----
Depreciation and amortization........... $ (255) $33,839 $23,440 Alternative minimum tax................. 5,387 (5,387) - Other................................... (194) 459 (148) ----- ------ ------ Total................................. $4,938 $28,911 $23,292 ----- ------ ------ ----- ------ ------ Depreciation and amortization fluctuations for 1993 are primarily attributable to the reversal of prior years' accumulated taxes as a result of the sale of a portion of Trimble County Unit 1 to IMPA. See Note 8, Trimble County Generating Plant, for a further discussion of the sale.
The following are the tax effects of book-tax temporary differences resulting in deferred tax assets and liabilities as of December 31, 1993 (in thousands of $):
Deferred Tax Assets: Investment tax credit................................. $ 36,961 Income taxes due to customers......................... 14,361 Other assets.......................................... 7,353 ------- $ 58,675 ------- -------
Deferred Tax Liabilities: Depreciation and other plant related items............ $322,544 Income taxes due from customers....................... 10,233 Other liabilities..................................... 7,458 ------- $340,235 ------- -------
The Company's effective income tax rate is computed by dividing the aggregate of current income taxes, deferred income taxes-net, and the investment tax credit-net, 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:
1993 1992 1991 ---- ---- ----
Statutory Federal income tax rate........ 35.0% 34.0% 34.0% State income taxes net of Federal benefit. 6.0 6.7 6.4 Amortization of investment tax credit..... (5.5) (4.7) (3.4) Other differences-net..................... 1.1 (.4) .1 ---- ---- ----
Effective Income Tax Rate................. 36.6% 35.6% 37.1% ---- ---- ---- ---- ---- ----
Note 4 - Preferred Stock - ------------------------
In May 1993, the Company issued $25 million of $5.875 Cumulative Preferred Stock. The proceeds from the sale were used to redeem the outstanding $8.90 Cumulative Preferred Stock. Note 5 - 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 1994 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, the Company issued two separate series of Pollution Control Bonds (a $35.2 million, Variable Rate Series, which had an interest rate of 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, 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, the Company issued $26 million of Pollution Control Bonds, 5.45% Series and redeemed the $26 million, 9.75% Series.
The Company also 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 5.9% rate. 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. At December 31, 1993, the rate on the JJ Kenny index was 3.25%.
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, 1993.
Note 6 - Notes Payable - ----------------------
The Company had no notes payable at December 31, 1993. At December 31, 1992, trust demand notes amounted to $8 million on which the composite interest rate was 3.45%.
At December 31, 1993, 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 1994. Management intends to renegotiate these lines when they expire.
Note 7 - Commitments and Contingencies - --------------------------------------
Construction Program. The Company had commitments, primarily in connection with its construction program, aggregating approximately $6 million at December 31, 1993. Construction expenditures for the calendar years 1994 and 1995 are estimated to total approximately $200 million.
FERC Order No. 636. Order No. 636, which was issued by FERC in 1992, required the Company and all other local distribution companies to revise their practices for purchasing and transporting gas. 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. Based on pipeline filings to date, the Company estimates that its share of transition costs, which must be approved by FERC, will be approximately $2 million to $3 million a year for both 1994 and 1995. 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. 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 1993, 1992, and 1991 was $2,436,000, $2,478,000, and $2,471,000, respectively. The future minimum annual lease payments under the lease agreement for years subsequent to December 31, 1993, are as follows (in thousands of $):
1994.............................. $ 2,148 1995.............................. 2,499 1996.............................. 2,850 1997.............................. 2,850 1998.............................. 2,850 Thereafter........................ 21,810 ------
Total.......................... $35,007 ------ ------
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 anticipates incurring capital expenditures during the next four years of approximately $40 million 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 excess sulfur dioxide emissions from its Mill Creek generating plant. The Company is currently conducting work in compliance with the agreed-upon schedule for remedial measures and has incurred total capital expenditures of approximately $24 million through 1993. Based on current remedial designs, the Company anticipates incurring additional capital costs of approximately $14 million for this project in 1994 as part of its ongoing capital construction program. 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. The Company currently estimates that property damage claims for the particulate emissions should be settled for an aggregate amount of approximately $12 million. Accordingly, the Company has recorded an accrual of this amount. In August 1993, 34 persons filed a complaint in Jefferson Circuit Court against the Company in which they are seeking certification of a class consisting of all persons within 2.5 miles of the Mill Creek plant. The court has not acted on the request for certification of a class. The plaintiffs seek compensation for alleged personal injury and property damage attributable to the particulate emissions from the Mill Creek plant, injunctive relief, a fund to finance future medical monitoring of area residents, and other relief. The Company intends to vigorously defend itself in the pending litigation.
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 retained a contractor to conduct certain air dispersion modeling. In 1992, the Company submitted a draft action plan and modeling schedule to the APCD and USEPA. The APCD and USEPA have approved the submittals and the Company's contractor is currently conducting additional modeling activities. Although it is expected that corrective action will be accomplished through capital improvements, until the contractor completes its modeling activities, the Company cannot determine the precise impact of this matter.
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 commenced site investigations at the two Company owned sites to determine if significant levels of contaminants are present. The Company has commenced discussions with the current owner of the third site regarding joint performance of a site investigation. The Company anticipates spending a total of approximately $1.3 million on site investigations expected to be completed by 1995. Preliminary testing at all three sites has identified contaminants typical of manufactured gas plant operations. Until an investigation and associated regulatory review is completed for each site, the Company will be unable to predict what, if any, cleanup activities may be necessary.
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 for contributions 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 preliminary discussions with the third-party plaintiffs. In the Company's opinion, the resolution of the issue will not have a material adverse impact on its financial position or results of operations. In February 1993, the Company was served with an amended complaint filed in federal district court in West Virginia by three potentially responsible parties (PRPs) against the Company and 39 other parties. The plaintiffs alleged that the parties were liable under CERCLA for in excess of $3 million in costs allegedly incurred by the plaintiffs in conducting cleanup activities at the Spencer Transformer Site located in Roane County, West Virginia. In November 1993, the federal court approved a consent decree that resolved the case as to the Company and nine other de minimis parties. Under the terms of the consent decree, the Company reimbursed the plaintiffs for $10,000 in cleanup costs. No further involvement of the Company is anticipated.
In June 1992, USEPA identified the Company as a 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. In November 1992, USEPA demanded immediate payment from the PRPs. To date, USEPA has identified nine PRPs for the site. The Company and several other parties have commenced discussions with USEPA. 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 contributions 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.
Based upon prior precedents established by the Commission and the Environmental Cost Recovery legislation, the Company expects to have an opportunity to recover, through future ratemaking proceedings, its costs associated with remedial measures required to comply with environmental laws and regulations.
Charitable Foundation. The Board of Directors of the Company has approved the formation of a tax-exempt charitable foundation with an initial contribution of up to $15 million. See Future Outlook under Item 7, Management's Discussion and Analysis, for a further discussion of this matter.
Note 8 - Trimble County Generating Plant - ----------------------------------------
Trimble County Unit 1, a 495-megawatt, coal-fired electric generating unit, was placed in commercial operation on December 23, 1990. This Unit, which during its first three years of commercial operations has operated more reliably than projected, has been the subject of numerous regulatory and legal proceedings. The current regulatory process involving Trimble County is related to an order issued by the Commission on July 1, 1988, which stated that 25% of the total cost of the Unit would not be allowed for ratemaking purposes. In a rehearing order issued in April 1989, the Commission reaffirmed its decision that the Company would not be allowed to include 25% of the cost of the Unit in customer rates; however, this order stated that "the disallowed portion of Trimble County remains with the Company and stockholders for their use."
In 1989, the Commission initiated a proceeding to determine the appropriate ratemaking treatment to carry out the order that disallowed rate recovery for 25% of the Unit. Prior to the start of the hearings in this proceeding, the Company filed a motion requesting the Commission to adopt a proposed plan to settle all of the issues surrounding Trimble County. Settlement discussions ensued between the Company, intervenors, and the Commission staff. On October 2, 1989, the Commission approved the settlement agreement reached between the Company and the Commission staff and, in accordance with the terms of the agreement, the Company refunded $2.5 million to its customers in 1989 and reduced its electric rates by $8.5 million for the year beginning January 1, 1990.
Certain intervenors, who participated in the proceedings but did not agree to the settlement, appealed the Commission's order approving the settlement to Franklin Circuit Court, claiming, among other things, that the Commission lacked the statutory authority to approve the agreement and that the intervenors who refused to sign the agreement were deprived of due process rights.
In February 1991, the Franklin Circuit Court vacated the October 2, 1989 order of the Commission approving the settlement agreement. On September 27, 1991, the Court issued an opinion requiring a refund to ratepayers in excess of $100 million as a result of the Commission's order that disallowed 25% of the total cost of Trimble County from customer rates. The Court further ordered the Company to post a bond if it appealed the Circuit Court's decision.
The Company posted a bond of $107 million and appealed all orders of the Circuit Court to the Kentucky Court of Appeals.
On April 23, 1993, the Kentucky Court of Appeals overturned the Franklin Circuit Court ruling previously entered in the case. Although the decision upheld the Circuit Court's order vacating the 1989 settlement agreement approved by the Commission, the appeals court ruled that the Franklin Circuit Court order of September 27, 1991, improperly set utility rates in ordering refunds. The intervenor parties requested the Kentucky Supreme Court to review the case, and their request for review was denied on October 20, 1993. Under Kentucky procedural rules, this ruling makes final the Court of Appeals decision and returns the case to the Commission for further proceedings.
The Commission has issued orders which set a portion of the procedural schedule for the case. Pursuant to the Commission's orders, the Company filed direct testimony on January 7, 1994. Intervenor parties are scheduled to file testimony on March 28, 1994. No date has been set for a hearing. The Company anticipates that the focus of Commission proceedings will be the determination of the appropriate ratemaking treatment to insulate ratepayers from 25% of Trimble County's costs and the amount of additional refunds, if any, that the Company should return to ratepayers. In previous proceedings in 1988, the Commission had authorized rate increases, subject to refund, of $11.4 million on an annual basis, pending a determination of the appropriate ratemaking treatment for the disallowance. The order remained in effect from May 1988 through December 1990, resulting in an amount subject to refund of approximately $30 million. The Company, through refunds and rate reductions, has already returned to its customers approximately $11 million of the total amount subject to refund. The Company's position is that no additional refunds are needed to carry out the Commission's objective of reflecting the disallowance of 25% of Trimble County in customer rates and the Company may be entitled to recover a portion, or all, of the amounts previously returned to customers. However, the Company is unable to predict the outcome of the Commission proceedings, the amount of additional refunds or recoveries, if any, that may be ordered or whether the Commission will revise its earlier position.
Sale of Portion of Trimble County. On February 28, 1991, the Company sold a 12.12% ownership interest in the Trimble County Unit to the Illinois Municipal Electric Agency, based in Springfield, Illinois, which is an agency of 30 municipalities that own and operate their own electric systems. The sale price was $94.2 million and a book gain of $4.2 million, after-tax, was recognized in 1991 as a result of this sale.
On February 1, 1993, the Indiana Municipal Power Agency (IMPA), based in Carmel, Indiana, purchased a 12.88% interest in the Trimble County plant. IMPA is composed of 31 municipalities that have joined together to meet their long-term electric power needs. The sale price was $91.1 million and an after-tax book gain of $3.2 million was recorded in 1993 as a result of this sale.
The Company has now completed the sale of the entire 25% of Trimble County that the Commission disallowed from customer rates. Note 9 - Jointly Owned Electric Utility Plant - ---------------------------------------------
As of December 31, 1993, the Company owned 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. IMEA pays for 12.12% of the operation and maintenance expenses, their proportionate share of incremental assets acquired and for fuel used.
. Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided interest in the Unit on February 1, 1993. IMPA is responsible for 12.88% of the operation and maintenance expenses, their proportionate share of incremental assets acquired and for fuel used.
The following data represent shares of the jointly owned property:
Trimble County -------------------------------------- LG&E IMPA IMEA Total ---- ---- ---- ----- Ownership interest.......... 75% 12.88% 12.12% 100% Mw capacity................. 371.25 63.75 60 495 Note 10 - 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.
1993 1992 1991 ---- ---- ---- (Thousands of $) Operating Information Operating Revenues Electric........................ $ 570,210 $ 521,669 $ 542,415 Gas............................. 204,915 178,526 166,291 --------- --------- --------- Total......................... $ 775,125 $ 700,195 $ 708,706 --------- --------- --------- --------- --------- --------- Pre-tax Operating Income Electric........................ $ 171,016 $ 154,547 $ 182,349 Gas............................. 17,436 15,122 13,576 --------- --------- --------- Total......................... $ 188,452 $ 169,669 $ 195,925 --------- --------- --------- --------- --------- --------- Other Information Depreciation and Amortization Electric........................ $ 69,753 $ 67,869 $ 65,236 Gas............................. 9,902 9,034 8,037 Non-Jurisdictional.............. 232 2,783 3,158 --------- --------- --------- Total......................... $ 79,887 $ 79,686 $ 76,431 --------- --------- --------- --------- --------- --------- Construction Expenditures Electric........................ $ 74,165 $ 75,630 $ 69,514 Gas............................. 24,622 25,545 18,538 --------- --------- --------- Total......................... $ 98,787 $ 101,175 $ 88,052 --------- --------- --------- --------- --------- --------- Investment Information-December 31 Identifiable Assets Electric........................ $1,616,595 $1,537,219 $1,524,018 Gas............................. 261,048 226,041 195,251 --------- --------- --------- Total......................... $1,877,643 $1,763,260 $1,719,269 Trimble County (a)................ - 87,794 89,824 Other Assets (b).................. 195,267 121,985 139,317 --------- --------- --------- Total Assets.................... $2,072,910 $1,973,039 $1,948,410 --------- --------- --------- --------- --------- ---------
(a) Represents the portion of Trimble County not allowed in customer rates. (b) Includes cash and temporary cash investments, accounts receivable, unamortized debt expense, and other property and investments. 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 & Co., independent public accountants whose report follows this Report of Management. Management has made available to Arthur Andersen & Co. 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 and the independent public accountants. These recommendations for the year ended December 31, 1993 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, 1993 and 1992, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As further discussed in Note 8, 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 2 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.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed under Item 14(a)2 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Louisville, Kentucky, Arthur Andersen & Co. January 28, 1994
-------------------------------------- SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
Operating revenues, net operating income, net income and net income available for common stock for the four quarters of 1993 and 1992 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
Quarters Ended ---------------------------------------------- (Thousands of $) March June September December ----- ---- --------- -------- Operating Revenues...... $208,631 $166,906 $200,408 $199,180 Net Operating Income.... 32,754 28,395 47,786 27,183 Net Income.............. 20,786 16,566 36,447 16,736 Net Income Available for Common Stock.......... 19,199 14,898 35,099 15,358
Operating Revenues...... $182,699 $150,908 $179,491 $187,097 Net Operating Income.... 28,985 27,849 41,850 27,145 Net Income.............. 15,915 15,301 29,050 13,527 Net Income Available for Common Stock.......... 13,510 13,676 27,474 11,960
--------------------------------------
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 28, 1994, 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, 1993 (page 29). Statements of Retained Earnings for the three years ended December 31, 1993 (page 30). Balance Sheets - December 31, 1993, and 1992 (page 31-32). Statements of Cash Flows for the three years ended December 31, 1993 (page 33-34). Statements of Capitalization - December 31, 1993, and 1992 (page 35-36). Notes to Financial Statements (pages 37-53). Report of Management (page 54). Report of Independent Public Accountants (page 55). Selected Quarterly Financial Data for 1993, and 1992 (page 56).
2. Financial Statement Schedules (included in Part IV): Schedule V - Property, Plant and Equipment for the three years ended December 31, 1993 (pages 72-77). Schedule VI - Accumulated Depreciation, Depletion, and Amortization of Property, Plant and Equipment for the three years ended December 31, 1993 (pages 78-80). Schedule VIII - Valuation and Qualifying Accounts for the three years ended December 31, 1993 (page 81). Schedule IX - Short-Term Borrowings for the three years ended December 31, 1993 (page 82). Schedule X - Supplementary Income Statement Information for the three years ended December 31, 1993 (page 83).
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 4.01 to Registration Statement 33-18302 and incorporated by reference herein]
3.02 Copy of Amendment to Articles of Incorporation, effective May 25, 1989. [Filed as Exhibit 3.01 to the Company's Form 10-Q for the quarter ended June 30, 1989 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, 1991, and incorporated by reference herein]
3.04 Copy of Amendment to Articles of Incorporation, effective April 8, 1993. [Filed as Exhibit 3.01 to the Company's Form 10-Q for the quarter ended March 31, 1993, and incorporated by reference herein]
3.05 Copy of Amendment to Articles of Incorporation, effective May 19, 1993.
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.
4.35 Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto.
4.36 Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto.
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 Agreement dated December 16, 1966, between Peabody Coal Company and the Company covering the purchase of coal. [Filed as Exhibit 10.23 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
10.24 Copy of Amendments to Coal Supply Agreement referred to in 10.23 above as follows: (i) Amendment effective July 1, 1970, (ii) effective January 1, 1975, and (iii) effective December 1, 1976. [Filed as Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
10.25 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]
10.26 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]
10.27 Copy of Agreement dated December 20, 1985, between Shawnee Coal Company and the Company covering the purchase of coal. [Filed as Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein]
10.28 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]
10.29 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] 10.30 Copy of Termination Agreement and Release dated February 1, 1989, between Peabody Coal Company and the Company canceling the Coal Supply Agreement dated December 16, 1966 referred to in Exhibit Nos. 10.23 and 10.24. [Filed as Exhibit 10.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
10.31 Copy of Agreements dated February 1 and February 15, 1989, between Peabody Development Company and the Company covering the purchase of coal. [Filed as Exhibit 10.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
10.32 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]
10.33 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]
10.34 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]
10.35 Copy of Agreement dated August 1, 1991, between Texas Gas Transmission Corporation and the Company covering the purchase of natural gas. [Filed as Exhibit 10.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein]
10.36 Copy of Sales Service Agreement between Texas Gas Transmission Corporation and the Company effective February 1, 1992. [Filed as Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.37 Copy of Sales Service Agreement between Texas Gas Transmission Corporation and the Company effective November 1, 1992. [Filed as Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.38 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]
10.39 Copy of Employment Agreement between Roger W. Hale and Louisville Gas and Electric Company, effective June 1, 1989, as amended. [Filed as Exhibit 10.39 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.40 Copy of 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]
10.41 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]
10.42 Copy of Modification No. 13 dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.
10.43 Copy of Modification No. 14 dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.
10.44 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.
10.45 Copy of Modification No. 15 dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. 10.46 Firm Transportation Agreement, dated November 1, 1993, between Texas Gas Transmission Corporation and the Company covering the transmission of natural gas.
10.47 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.
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.
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.
10.48 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]
10.49 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]
12 Computation of Ratio of Earnings to Fixed Charges
23 Consent of Independent Public Accountants
24 Power of Attorney (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]
Employment Agreement between Roger W. Hale and Louisville Gas and Electric Company, effective June 1, 1989, as amended. [Filed as Exhibit 10.39 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992]
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]
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]
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 following 8-K reports were filed during the fourth quarter of 1993:
(i) On October 27, 1993, a report on Form 8-K was filed announcing the following:
Trimble County Generating Plant. On October 20, 1993, the Kentucky Supreme Court declined to review a Kentucky Court of Appeals order overturning a lower court's order that had improperly directed the Company to refund approximately $150 million to its customers in a case involving the Company's Trimble County electric generating station.
Management Change. Walter M. Higgins, III, President and Chief Operating Officer of the Company resigned to accept the position of President and Chief Operating Officer of Sierra Pacific Resources. Sierra Pacific Resources indicated plans for Mr. Higgins to become Chief Executive Officer early in 1994.
(ii) On November 23, 1993, a report on Form 8-K was filed announcing that LG&E Energy Corp., of which the Company is the principal subsidiary, would undergo a major realignment and formation of new business units effective January 1, 1994, to reflect its outlook for rapidly emerging competition in all segments of the energy services industry.
The amounts of royalties and advertising costs charged to operating expenses were each less than one percent of total operating revenues. 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 28, 1994 By 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;
DAVID B. LEWIS Director;
ANNE H. MCNAMARA Director;
T. BALLARD MORTON, JR. Director; and
DR. DONALD C. SWAIN Director.
By M. L. FOWLER March 28, 1994 - ------------------------------------------------ (Attorney-In-Fact)