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 277,000 customers and electricity to approximately 351,000 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 transports gas and provides electric service, but which maintains its own distribution systems. The Company also provides gas service in limited additional areas. The Company's coal-fired electric generating plants, which are all equipped with systems to remove sulfur dioxide, produce most of the Company's electricity; the remainder is generated by a hydroelectric power plant and combustion turbines. Underground natural 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 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), a 495-megawatt, coal-fired electric generating unit, which the Company began constructing in 1979, was placed in commercial operation on December 23, 1990. Trimble County had been subject to numerous reviews by the Public Service Commission of Kentucky (Kentucky Commission or Commission). On December 8, 1995, the Commission approved a settlement agreement filed by the Company and all intervenors in the Trimble County proceedings, including various consumer interest groups and government agencies, that in effect, resolved all of the regulatory and legal issues related to the appropriate ratemaking treatment to exclude 25% of the Trimble County costs from customer rates. The Company owns a 75% undivided interest in Trimble County. For a more detailed discussion of the proceedings relating to Trimble County, see Electric Operations and Notes 14 and 15 of Notes to Financial Statements under Item 8.
With the passage of the Clean Air Act Amendments of 1990 (the Act), the Company already complied with the stringent sulfur dioxide emission limits required by the year 2000 as it had previously installed scrubbers on all of its coal-fired generating units. Since then, as part of its ongoing construction program, the Company has spent $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the Act on the Company has been minimal. However, the Company is closely monitoring a number of significant regulatory developments. In November 1996, the United States Environmental Protection Agency (USEPA) announced its proposal to revise the National Ambient Air Quality Standards for ozone and particulate matter. In November 1996, USEPA also announced its intent to direct certain states to address long range ozone transport from Midwest emission sources which
allegedly contribute to ozone problems in the Northeast. While management is unable to predict the outcome or exact impact of these ongoing regulatory proceedings, the Company continues to be well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities. For a more detailed discussion of the Clean Air Act and other environmental issues, see Environmental Matters under this Item, Item 3, Item 7, and Note 13 of the Notes to Financial Statements under Item 8.
The Company has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; a write-off of previously deferred expenses; an increase in focus on not only commercial and industrial customers, but residential customers as well; an increase in employee involvement and training; a major realignment and formation of new business units, and continuous modifications of its organizational structure.
In 1996, the Power Generation Division of the Company introduced initiatives designed to maintain the Company's low-cost advantage in this increasingly competitive segment of the energy-services industry. To optimize the daily operation of the plants, the Company established new work processes that encourage decision making at the optimal level.
The Company is continually developing ways to enhance the service it provides to customers, including the formation of strategic partnerships with other service providers. These partnerships increase the product offerings available to customers, allow the Company to leverage existing systems and position it in new markets for the future. Partnerships also allow the Company to be more innovative by creating cutting-edge offerings that might not be possible otherwise. The Company is now using its customer service centers as a central portal for other utility services. Through a joint effort with the Louisville Water Company, customers can now arrange for new services or make payment to both utilities through the Company. Customers can also apply for low-interest loans to purchase a variety of energy-efficient household appliances and equipment, such as natural gas furnaces, through the Company's Home Energy Loan Program. These are conveniences that enhance customers' lives and help secure our relationships for the future.
By using gas storage fields strategically, the Company can buy gas when prices are low, store it, and retrieve the gas when demand is high. Accessing least cost gas was made easier in November 1993 when the Federal Energy Regulatory Commission Order No. 636 went into effect. Previously, the Company and other utilities purchased most of their gas services from pipeline companies. The order "unbundled" gas services, allowing utilities to purchase gas, transportation, and storage services separately from many different sources. Currently, the Company buys competitively priced gas from several large producers under contracts of varying duration. By purchasing from multiple suppliers and storing any excess gas, the Company is able to secure favorably priced gas for its customers. Without storage capacity, the Company would be forced to buy additional gas when customer demand increases, which is usually when the price is highest.
During 1995, the Company negotiated a five year transportation agreement with Tennessee Gas Pipeline Company (Tennessee) to become the Company's second natural gas pipeline transporter. The agreement with Tennessee became effective November 1, 1996. For many years, Texas Gas Transmission Corporation (Texas Gas) has been the sole provider of gas transport services to the Company. For further discussion, see Gas Supply.
For the year ended December 31, 1996, 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 ................... $202,318 $125,327 $327,645 44% Commercial .................... 163,027 47,415 210,442 29 Industrial .................... 110,914 21,229 132,143 18 Public authorities ............ 54,318 11,731 66,049 9 -------- -------- -------- --- Total-ultimate consumers .... 530,577 205,702 736,279 100% === Sales for resale .............. 67,854 -- 67,854 Gas transportation-net ........ -- 6,850 6,850 Miscellaneous ................. 8,265 1,867 10,132 -------- -------- -------- Total ....................... $606,696 $214,419 $821,115 ======== ======== ========
See Note 16 of Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 1996.
Electric Operations
The sources of electric operating revenues and the volumes of sales for the three years ended December 31, 1996, were as follows:
1996 1995 1994 ----------- ------------ ----------- ELECTRIC OPERATING REVENUES (Thousands of $): Residential ......................... $ 202,318 $ 201,357 $ 194,145 Small commercial and industrial ..... 74,034 73,074 70,916 Large commercial .................... 88,993 87,497 84,931 Large industrial .................... 110,914 110,800 108,004 Public authorities .................. 54,318 53,861 53,191 Refund - Trimble County settlement .. -- (28,300) -- ----------- ------------ ----------- Total-ultimate consumers ........... 530,577 498,289 511,187 Sales for resale .................... 67,854 37,471 42,720 Miscellaneous ....................... 8,265 6,577 5,039 ----------- ------------ ----------- Total .............................. $ 606,696 $ 542,337 $ 558,946 =========== ============ ===========
ELECTRIC SALES (Thousands of kwh): Residential ......................... 3,382,124 3,415,225 3,204,330 Small commercial and industrial ..... 1,130,558 1,112,130 1,073,152 Large commercial .................... 1,850,294 1,802,035 1,729,668 Large industrial .................... 3,058,723 3,023,543 2,874,411 Public authorities .................. 1,122,147 1,113,063 1,085,741 ----------- ------------ ----------- Total-ultimate consumers ........... 10,543,846 10,465,996 9,967,302 Sales for resale .................... 3,589,090 2,000,607 2,315,311 ----------- ------------ ----------- Total .............................. 14,132,936 12,466,603 12,282,613 =========== ============ ===========
At December 31, 1996, the Company had 351,295 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 1996 was approximately .96 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.
The 1996 maximum local peak load of 2,282 Mw occurred on Wednesday, August 7 when the temperature at the time of peak was 93 degrees Fahrenheit (average for the day was 84 degrees Fahrenheit). On Thursday, August 17, 1995, the Company set its all-time record local peak load of 2,357 Mw, when the temperature at the time of peak reached 94 degrees Fahrenheit (average for the day was 86 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 Company's current reserve margin is 16%. At February 28, 1997, the Company owned steam and combustion turbine generating facilities with a capacity of 2,512 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 whose primary customer is the Portsmouth Area uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio. The Company has direct interconnections with 11 utility companies in the area and has agreements with each interconnected utility for the purchase and sale of capacity and energy. The Company also has agreements with an increasing number of entities throughout the United States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission system.
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, has a 12.12% ownership interest in the Company's Trimble County Unit 1. The Indiana Municipal Power Agency (IMPA), based in Carmel, Indiana, has a 12.88% ownership 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 Trimble County and for fuel and reactant used. They are also responsible for their proportionate share of incremental capital assets acquired. See Note 15 of Notes to Financial Statements under Item 8 for further discussion.
Gas Operations
The sources of gas operating revenues and the volumes of sales for the three years ended December 31, 1996, were as follows:
1996 1995 1994 -------- -------- -------- GAS OPERATING REVENUES (Thousands of $): Residential ........................... $125,327 $107,762 $110,553 Commercial ............................ 47,415 38,161 40,474 Industrial ............................ 21,229 17,430 27,956 Public authorities .................... 11,731 8,679 12,930 -------- -------- -------- Total-ultimate consumers ............. 205,702 172,032 191,913 Gas transportation-net ................ 6,850 7,821 6,759 Miscellaneous ......................... 1,867 1,273 1,457 -------- -------- -------- Total ................................ $214,419 $181,126 $200,129 ======== ======== ========
GAS SALES (Millions of cu. ft.): Residential ........................... 25,531 24,242 22,935 Commercial ............................ 10,656 9,885 9,450 Industrial ............................ 5,190 5,188 7,505 Public authorities .................... 2,790 2,423 3,268 -------- -------- -------- Total-ultimate consumers ............. 44,167 41,738 43,158 Gas transported ....................... 12,540 12,241 6,854 -------- -------- -------- Total ................................ 56,707 53,979 50,012 ======== ======== ========
At December 31, 1996, the Company had 277,493 gas customers.
The Company has underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers.
Reflecting the changing nature of the gas business, a number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through the Company's distribution system. Generally, transportation of natural gas for the Company's customers does not have an adverse effect on earnings because of the offsetting decrease in gas supply expenses. Transportation rates are designed to make the Company economically indifferent as to whether gas is sold or merely transported.
The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees Fahrenheit. During 1996, the maximum day gas sendout was 521,000 Mcf, occurring on February 2, when the average temperature for the day was 6 degrees Fahrenheit. Supply on that day consisted of 202,000 Mcf from purchases, 275,000 Mcf delivered from underground storage, and 44,000 Mcf transported for industrial customers. For further discussion, see Gas Supply.
Under FERC Order No. 636, pipelines may recover costs associated with the transition to and implementation of this order from pipeline customers, including the Company. The Company is recovering these costs from its customers through its gas supply clause.
Regulation and Rates
The Kentucky Commission has regulatory jurisdiction over the rates and service of the Company and over the issuance of certain of its securities. The Company is a "public utility" as defined in the Federal Power Act, and is subject to the jurisdiction of the Department of Energy and the FERC with respect to the matters covered in such Act, including the sale of electric energy at wholesale in interstate commerce. In addition, the FERC has sole jurisdiction over the issuance by the Company of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation under Item 7 and Note 2 of Notes to Financial Statements under Item 8.
Increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all of the Company's electric customers by means of the Company's fuel adjustment clause. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals for the purpose of additional examination and transfer of the then current fuel adjustment charge or credit to the base charges. The Commission also requires that electric utilities, including the Company, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities.
The Company's gas rates contain a gas supply clause (GSC), whereby increases or decreases in the cost of gas supply are reflected in the Company's rates, subject to approval of the Kentucky Commission. The GSC procedure prescribed by order of the Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.
On December 8, 1995, the Commission approved a settlement agreement that, in effect, resolved all the regulatory and legal issues related to the appropriate ratemaking treatment to exclude 25% of the Trimble County plant costs from customer rates. See Note 14 of Notes to Financial Statements under Item 8 for further discussion of this matter.
On April 6, 1995, in response to an application filed by the Company, the Commission approved, with modifications, an environmental cost recovery surcharge that increased electric revenues by $3.2 million in 1995 and $2.4 million in 1996. The surcharge became effective May 1, 1995. An appeal of the Commission's April 6 order by various intervenors in the proceeding (including the Kentucky Attorney General) is currently pending in the Franklin Circuit Court of Kentucky. The Company is contesting the legal challenges to the surcharge, but cannot predict the outcome of the appeal. The amount of refunds that may be ordered, if any, are not expected to have a material adverse effect on the Company's financial position or results of operations. See Rates and Regulation under Item 7 for a further discussion.
In January 1994, the Company implemented a Commission approved demand side management (DSM) program. The program contains a rate mechanism that provides for the recovery of DSM program costs, allows the Company to recover revenues due to lost sales associated with the DSM programs and provides the Company an incentive for implementing DSM programs. See Rates and Regulation under Item 7 for a further discussion of DSM.
On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued Orders 888 and 889. Order 888 requires all public utilities to file Open Access Transmission Tariffs. These tariffs will allow third parties to utilize a utility's transmission assets under comparable terms and conditions as the utility. The Company filed its Open Access Transmission Tariff on July 9, 1996, to comply with FERC's Order 888. See Rates and Regulation under Item 7 for a further discussion of this matter.
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; requires 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 precludes the Company from guaranteeing any obligations of Energy Corp. without prior written consent from the Kentucky Commission. In addition, the 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 ensure that there will be adequate capacity and reliability to meet the 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.
During the five years ended December 31, 1996, gross property additions amounted to $496 million. Internally generated funds for the five year period were sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 18% of total utility plant at December 31, 1996, and consisted of $368 million for electric properties and $128 million for gas properties. Gross retirements during the same period were $94 million, consisting of $76 million for electric properties and $18 million for gas properties.
At December 31, 1996, the Company's embedded cost of long-term debt was 6.05% and its ratio of earnings to fixed charges was 5.07. See Exhibit 12. For a further discussion of construction expenditures and financing, see Liquidity and Capital Resources under Item 7.
Coal Supply
Over 90% of the Company's present electric generating capacity is coal-fired, the remainder being made up of a hydroelectric plant and combustion turbine peaking units fueled by natural gas and oil. Coal will be the predominant fuel used by the Company in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies. The Company has no nuclear generating units and has no plans to build any in the foreseeable future.
In January 1996, the Company bought out the last year of its three year contract with Andalex Resources, Inc. at a cost of $3.5 million. The Kentucky Commission allowed the recovery of the buyout expense through the Company's fuel adjustment clause. As a result of the buyout of the coal contract, the Company's customers realized a net savings in excess of $1 million.
The Company has entered into coal supply agreements with various suppliers for coal deliveries for 1997 and beyond. The Company normally augments its coal supply agreements with spot market purchases which, during 1996, 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, 1996, a coal inventory of approximately 650,000 tons, or a 36 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%-4.5% 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. Deliveries to the Cane Run and Trimble County plants are by rail and barge, respectively.
The average delivered cost of coal purchased by the Company, per ton and per million Btu, for the periods shown were as follows:
1996 1995 1994 ---- ---- ----
Per ton........................... $21.73 $23.68 $25.27 Per million Btu................... .97 1.04 1.10
This downward trend in the delivered cost of coal is expected to continue through 1997.
Gas Supply
Prior to the implementation of FERC Order No. 636, the Company had 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, beginning in 1996, Tennessee Gas Pipeline Company (Tennessee). In addition, the Company purchases natural gas from many other sources under contracts for varying periods of time.
Under Order No. 636, pipelines may recover costs associated with the transition to and implementation of this order from pipeline customers, including the Company. The Commission issued an order, based on proceedings that were held to investigate the impact of Order No. 636 on utilities and ratepayers in Kentucky, providing that transition costs assessed on utilities by the pipelines, which are clearly identifiable as being related to the cost of the commodity itself, are appropriate to be recovered from customers through the gas supply clause. Transition costs are billed pursuant to orders issued by FERC in transition cost regulatory proceedings.
The Company transports on the Texas Gas system under No-Notice Service (NNS) and Firm Transportation (FT) rates. During the winter months, the Company has 184,900 MMBtu (180,390 Mcf) per day in NNS. The Company does not transport on the Texas Gas system under FT rates during the winter months. During the summer months, the Company's NNS level is 111,000 MMBtu (108,293 Mcf) per day, and its FT service level is 24,000 MMBtu (23,415 Mcf) per day. Each of these NNS and FT agreements with Texas Gas expire in equal portions in 1998, 2000, and 2001. Each agreement includes a unilateral five year roll-over provision exercisable at the Company's option. Effective November 1, 1996, the Company also terminated a transportation agreement with Texas Gas which provided for 30,000 MMBtu (29,268 Mcf) per day in FT service throughout the year. On November 1, 1996, the Company initiated service under a five year transportation agreement with Tennessee for 30,000 MMBtu (28,986 Mcf) per day in firm transportation service under Tennessee's Rate FT-A. For the previous thirty years, Texas Gas had been the sole provider of gas transportation services to the Company.
During 1996, the Company participated in several regulatory proceedings at FERC. During 1997, Texas Gas is expected to file for a change in its rates as required under the settlement in its last rate case in Docket RP94-423. The Company plans to participate in that and other proceedings, as appropriate.
The Company also has a portfolio of supply arrangements with various suppliers in order to meet its firm sales obligations. These gas supply arrangements include pricing provisions which are market-responsive. These firm supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve the Company's customers.
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 1995-1996 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 $3.46 in 1996, $2.62 in 1995, and $2.78 in 1994.
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 1996, expenditures for pollution control facilities represented $101 million or 20% of total construction expenditures. The cost of operating and maintaining scrubber-related facilities amounted to $22 million in 1996 and $21 million in 1995. See Note 13 of Notes to Financial Statements under Item 8 for a discussion of specific environmental proceedings affecting the Company.
Labor Relations
The Company's approximately 1,500 operating, maintenance, and construction employees are members of the International Brotherhood of Electrical Workers (IBEW) Local 2100. The current three year contract will expire in November 1998.
Employees
The Company had 2,500 full-time employees at December 31, 1996.
ITEM 2.

ITEM 2. PROPERTIES.
The Company's power generating system consists of the coal-fired units operated at its three steam generating stations. Combustion turbines supplement the system during peak or emergency periods. At February 28, 1997, the Company owned 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 480,000 1,470,000 ------- Cane Run-near Louisville, Ky. Unit 4.......................... 1962 155,000 Unit 5.......................... 1966 168,000 Unit 6.......................... 1969 240,000 563,000 ------- Trimble County-Bedford, Ky. Unit 1.......................... 1990 371,000(a)
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 ------- ---------- 2,512,000 ==========
(a) Amount shown represents the Company's 75% interest in Trimble County. The Company is responsible for operation of Unit 1 and is reimbursed by IMEA and IMPA for expenditures related to Trimble County based on their proportionate share of ownership interest. See Note 15 of Notes to Financial Statements, Jointly Owned Electric Utility Plant, under Item 8 for further discussion on ownership.
The Company also owns an 80 Mw hydroelectric generating station located in Louisville, operated under license issued by the FERC.
At December 31, 1996, the Company's electric transmission system included 21 substations with a total capacity of approximately 11,026,897 Kva and approximately 652 structure miles of lines. The electric distribution system included 83 substations with a total capacity of approximately 3,383,530 Kva, 3,537 structure miles of overhead lines, 274 miles of underground conduit, and 5,420 miles of underground conductors.
The Company's gas transmission system includes 178 miles of transmission mains, and the gas distribution system includes 3,528 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 in June 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 much of the property owned by the Company.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS.
Rates, Regulatory Matters, and Trimble County Generating Plant
For a discussion of current regulatory matters and a detailed discussion of the Trimble County Unit 1 settlement agreement, see Rates and Regulation under Item 7 and Notes 2 and 14 of Notes to Financial Statements under Item 8.
Statewide Power Planning
In March 1995, the Commission staff issued its report on its review of the Company's 1993 biennial Integrated Resource Plan. The Staff Report specifically found that the Company's plan contained some of the better analyses among those filed by the electric utilities under the Commission's jurisdiction, and presented several suggestions for the Company's consideration when it develops its next plan. In an order issued March 17, 1995, the Commission formally closed its proceeding for the review of the Company's plan. On May 5, 1995, the Commission granted the Company's request to waive the requirement that the Company file an Integrated Resource Plan during 1995. On July 21, 1995, the Kentucky Commission amended its Integrated Resource Planning regulations to replace the biennial filing requirement with a triennial requirement. The amended regulations also specified that the Company's next Integrated Resource Plan is to be filed 39 months from the effective date of the amended regulation, or October 21, 1998.
Environmental
For a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run generating plants, manufactured gas plant sites, and certain other environmental issues, see Note 13 of Notes to Financial Statements under Item 8.
Other
In the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against the Company. To the extent that damages are assessed in any of these lawsuits, the Company believes that its insurance coverage is adequate. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company's consolidated financial position or results of operations.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
---------------------
Executive Officers of the Company.
Effective Date of Election to Present Name Age Position Position - ---- --- -------- -------------------
Roger W. Hale 53 Chairman of the Board and Chief Executive Officer January 1, 1992
Victor A. Staffieri 41 President January 1, 1994
John R. McCall 53 Executive Vice President, General Counsel and Corporate Secretary July 1, 1994
Rebecca L. Farrar 37 Vice President, Gas Service Business February 15, 1995
M. Lee Fowler 60 Vice President and Controller September 1, 1988
Wendy C. Heck 43 Vice President, Information Services January 1, 1994
Chris Hermann 49 Vice President and General Manager, Wholesale Electric Business January 1, 1993
Paul W. Thompson 40 Vice President, Retail Electric Business September 15, 1996
Charles A. Markel III 49 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 8, 1997.
There are no family relationships between executive officers of the Company.
Mr. Hale, 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, 1992: Ms. Heck was Vice President-Fuels and Operating Services prior to January 1993, and Vice President-Fuels and Information Services thereafter; Mr. Hermann was General Manager-Wholesale Electric prior to January 1993; Mr. Markel was Senior Vice President and Chief
Financial Officer prior to January 1993. Effective January 1993, Mr. Markel was named Corporate Vice President-Finance, and Treasurer of the parent company, LG&E Energy Corp.
Prior to election to his current position, Mr. Staffieri was Senior Vice President-Public Policy, and General Counsel of the Company, and prior to November 1992, Senior Vice President, General Counsel and Corporate Secretary. Prior to March 1992, Mr. Staffieri was employed by Long Island Lighting Company and held the position of General Counsel and Secretary.
Prior to election to his current position, Mr. McCall was Partner and Litigation Chairman of Brown, Todd & Heyburn, a law firm.
Prior to election to her current position, Ms. Farrar was employed by South Carolina Electric and Gas Company and held the position of General Manager, Gas Operations from July 1994 to February 1995; Division Manager, Central Division-Gas Operations prior to July 1994; and General Manager, Northern Division-Gas Operations prior to February 1992.
Prior to election to his current position, Mr. Thompson was Vice President-Business Development for the parent company, LG&E Energy Corp. from July 1994 to September 1996; General Manager-Gas Operations for the Company prior to July 1994; and Director-Business Development for Energy Corp. prior to December 1993.
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:
1996 1995 ---- ---- (Thousands of $) First Quarter............. $18,500 $18,000 Second Quarter............ 18,500 34,000 Third Quarter............. 18,500 18,000 Fourth Quarter............ 19,200 18,500
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA.
Management's Discussion and Analysis of Results of Operations and Financial Condition and of the Notes to Financial Statements should be read in conjunction with the above information.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION.
The following discussion and analysis by management focuses on those factors that had a material effect on the Company's financial results of operations and financial condition during 1996, 1995, and 1994 and should be read in connection with the financial statements and notes thereto.
Some of the following discussion may contain forward looking statements that are subject to certain risks, uncertainties and assumptions. Such forward looking statements are intended to be identified in this document by the words "anticipate," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include: general economic conditions; business and competitive conditions in the energy industry; change in federal or state legislation; unusual weather; actions by state or federal regulatory agencies affecting rates; and other factors described from time to time in Louisville Gas and Electric Company's reports to the Securities and Exchange Commission.
RESULTS OF OPERATIONS
Net Income
Net income for 1996 increased $7.9 million over 1995 excluding a $16.9 million charge against net income in 1995 to recognize the effects of a settlement of the long-standing issues surrounding the Company's Trimble County electric generating plant. Without excluding the Trimble County charge-off, net income increased $24.8 million over 1995. The $7.9 million increase in net income is primarily the result of a significantly higher level of wholesale electric sales and increased retail sales of electricity and natural gas, partially offset by increased operation and maintenance expenses.
The Company's net income increased $24.9 million for 1995 over 1994 in spite of recording the Trimble County settlement charge mentioned in the preceding paragraph. In 1994 net income of $58.3 million included the write-off of certain non-recurring items ($23.9 million), the expense of establishing a charitable foundation ($8.9 million), and the adoption of Statement of Financial Accounting Standards No. 112, Employers' Accounting for Post-Employment Benefits ($3.4 million). Without consideration of the unusual charges against income in 1995 and 1994 as discussed above, the Company's 1995 net income increased $5.6 million over 1994. This improvement was primarily due to higher retail electric sales during 1995 partially offset by increased purchased power expenses resulting from unplanned power plant outages.
Revenues
A comparison of operating revenues for the years 1996 and 1995, excluding the Trimble County settlement (which reduced electric revenues by $28.3 million in 1995), with the immediately preceding year reflects both increases and decreases, which have been segregated by the following principal causes (in thousands of $):
Electric revenues increased in 1996 compared with 1995 primarily because of an increase in sales of electricity for resale which resulted from aggressive marketing efforts. Gas revenues increased as a result of the higher cost of natural gas in 1996 and because of increased sales to ultimate consumers (6%) caused mainly by colder weather experienced in the first quarter of the year.
Electric revenues increased in 1995 mainly because of an increase in sales to ultimate consumers as a result of the warmer summer weather and improved economic conditions in the Company's service territory. Gas revenues decreased as a result of lower gas supply adjustment revenues, which reflected the lower cost of natural gas in 1995.
Expenses
Fuel for electric generation and gas supply expenses comprise 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 are reflected in the Company's rates, subject to approval by the Public Service Commission of Kentucky (Kentucky Commission or Commission).
Fuel expenses increased $11.7 million (8%) in 1996 primarily because of a 12% increase in generation ($16 million), partially offset by a decrease in the cost of coal burned ($4.3 million). Fuel expenses decreased $5.6 million (4%) in 1995 as compared to 1994 due to a decrease in the cost of coal burned ($7.5 million) partially offset by increased generation of 2%. The average delivered cost per ton of coal purchased was $21.73 in 1996, $23.68 in 1995, and $25.27 in 1994. This downward trend in the delivered cost of coal is expected to continue through 1997.
Power purchased expense in 1996 of $16.6 million was approximately the same as in 1995. Power was purchased in 1996 primarily to supplement generation requirements related to wholesale electric power sales. Power purchased in 1995 increased $7.1 million over 1994 primarily because of
increased purchases resulting from unplanned outages at the electric generating plants during the extremely hot summer weather.
Gas supply expenses increased $29.7 million (27%) mainly because of the higher unit cost of net gas supply ($21.8 million) and an increase in the volume of gas delivered to the distribution system ($7.9 million). Gas supply expenses decreased $20.8 million (16%) in 1995 because of the lower cost of net gas supply ($18.7 million) and a decrease in the volume of gas delivered to the distribution system ($2.1 million). The average unit cost per Mcf of purchased gas was $3.46 in 1996, $2.62 in 1995, and $2.78 in 1994.
Other operation expenses increased $8.7 million (6%) over 1995 primarily because of increased costs to operate the Company's electric power plants ($2.9 million), the electric and gas transmission and distribution systems ($1.9 million), and because of the recognition of credits to expense in 1995 for settlement proceeds received related to a commercial dispute ($6.0 million).
In 1995 the Company received cash proceeds of $8 million in connection with the settlement of a commercial dispute. Pursuant to a study to determine the proper amount of income to be recognized, the Company recognized $6 million as a reduction of 1995 operation expense. After further study and the resolution of the remaining legal issues, the $2 million balance was applied as a reduction of operation expense in 1996.
Maintenance expenses increased $2.7 million (5%) over 1995 primarily due to increased storm damage repairs ($1.8 million) and an increase in electric power plant expenses ($.9 million). Maintenance increased $3.4 million in 1995 over 1994 primarily as a result of an increase in repairs at the electric power plants ($4.2 million), partially offset by a decrease in storm damage expenses ($1 million).
Non-recurring charges in 1994 of $38.6 million include the Company's write-off of costs in connection with early retirements and workforce reductions that occurred in 1992 and 1993, costs in connection with property damage claims pertaining to particulate emissions from the Mill Creek electric generating plant, and certain costs previously deferred resulting from adoption of Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS. See Note 3 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 $)
STATEMENTS OF RETAINED EARNINGS (Thousands of $)
Years Ended December 31 ------------------------------ 1996 1995 1994 -------- -------- -------- Balance January 1 ............................. $181,049 $193,895 $194,903 Add net income ................................ 107,941 83,184 58,320 -------- -------- -------- 288,990 277,079 253,223 -------- -------- --------
Deduct: Cash dividends declared on stock: 5% cumulative preferred ............... 1,075 1,075 1,075 7.45% cumulative preferred ............ -- 1,527 1,598 Auction rate cumulative preferred ..... 2,024 2,240 1,686 $5.875 cumulative preferred ........... 1,469 1,469 1,469 Common ................................ 75,200 89,000 53,500 Preferred stock redemption expense ...... -- 719 -- -------- -------- -------- 79,768 96,030 59,328 -------- -------- --------
Balance December 31 ........................... $209,222 $181,049 $193,895 ======== ======== ========
The accompanying notes are an integral part of these financial statements.
LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Thousands of $)
The accompanying notes are an integral part of these financial statements.
LOUISVILLE GAS AND ELECTRIC COMPANY BALANCE SHEETS (Thousands of $)
The accompanying notes are an integral part of these financial statements.
LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Thousands of $)
The accompanying notes are an integral part of these financial statements.
LOUISVILLE GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Louisville Gas and Electric Company (the Company) is the primary subsidiary of LG&E Energy Corp. The Company is a regulated public utility that is engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas in Louisville and adjacent areas in Kentucky. LG&E Energy Corp. is an exempt energy services holding company with wholly-owned subsidiaries consisting of the Company, LG&E Energy Systems Inc., and LG&E Gas Systems Inc. All of the Company's Common Stock is held by LG&E Energy Corp.
Certain reclassifications have been made to the 1995 financial statements to conform to the 1996 presentation with no impact on previously reported income.
UTILITY PLANT. The Company's plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base, and, accordingly, the Company has not recorded any allowance for funds used during construction.
The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost plus removal expense less salvage value is charged to the reserve for depreciation. When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized.
DEPRECIATION. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for 1996 and 1995 were 3.3% (3.2% electric, 3.3% gas, and 6% common); and for 1994, 3.3% (3.2% electric, 3.3% gas, and 5% 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.
FINANCIAL INSTRUMENTS. The Company uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt, and it uses exchange-traded U.S. Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly. Gains and losses on U.S. Treasury note and bond futures used to hedge investments in preferred stocks are initially deferred and classified as unrealized gains or losses on marketable securities in common equity and then charged or credited to other income and deductions when the securities are sold. See Note 4, Financial Instruments.
DEBT PREMIUM AND EXPENSE. Debt premium and expense are amortized over the lives of the related debt issues, consistent with regulatory practices.
DEFERRED INCOME TAXES. Deferred income taxes have been provided for all material book-tax temporary differences.
INVESTMENT TAX CREDITS. Investment tax credits resulted from provisions of the tax law that permitted a reduction of the Company's tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits.
REVENUE RECOGNITION. Revenues are recorded based on service rendered to customers through month end. The Company accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period. Under an agreement approved by the Public Service Commission of Kentucky (Kentucky Commission or Commission), the Company has implemented a demand side management program and a "decoupling mechanism," which allows the Company to recover a predetermined level of revenue on electric and gas residential sales. See Management's Discussion and Analysis, Rates and Regulation, for further discussion.
FUEL AND GAS COSTS. The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system.
MANAGEMENT'S USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 13, Commitments and Contingencies, for a further discussion.
NEW ACCOUNTING PRONOUNCEMENTS. LONG-LIVED ASSETS. The Company adopted Statement of Financial Accounting Standards No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF (SFAS No. 121) in the first quarter of 1996. This new standard requires that long-lived assets and certain intangibles be reviewed for impairment and possible write-down to fair value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company has performed these impairment reviews on certain long-lived assets and has determined their carrying amounts to be recoverable. Management continues to monitor current and anticipated future operating conditions, legal requirements and regulatory environment for circumstances that may trigger potential asset impairments.
TRANSFERS AND EXTINGUISHMENTS. In June 1996, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 125, ACCOUNTING FOR TRANSFERS AND SERVICING OF FINANCIAL ASSETS AND EXTINGUISHMENTS OF LIABILITIES (SFAS No. 125), effective for all transfers and servicing of financial assets and extinguishments of liabilities occurring after December 31, 1996. The Company plans to adopt the provisions of SFAS No. 125 in the first quarter of 1997. The Company does not expect the adoption of SFAS No. 125 to have a material adverse impact on its financial position or results of operation.
ENVIRONMENTAL REMEDIATION. Effective January 1, 1997, the Company will adopt the provisions of Statement of Position (SOP) 96-1, ENVIRONMENTAL REMEDIATION LIABILITIES. This statement provides authoritative guidance for recognition, measurement, and disclosure of environmental remediation liabilities in financial statements. Due to the Company's previous recognition of this type of liability, adoption is not expected to have a material impact on its financial position or results of operation. See Note 13, Commitments and Contingencies, for a further discussion on the Company's environmental commitments and contingencies.
NOTE 2 - RATES AND REGULATORY MATTERS
The Company conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by the Federal Energy Regulatory Commission (FERC) and the Kentucky Commission. The Company is subject to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71). Under SFAS No. 71, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in the balance sheets as of December 31 (in thousands of $):
1996 1995 -------- -------- Unamortized loss on bonds .......................... $ 17,162 $ 16,443 Unamortized extraordinary retirements .............. 4,087 6,935 Manufactured gas sites ............................. 3,244 3,220 Other .............................................. 3,236 3,328 -------- -------- Total regulatory assets ............................ 27,729 29,926
Deferred income taxes - net ........................ (77,287) (88,242) -------- --------
Regulatory assets and (liabilities) - net .......... $(49,558) $(58,316) ======== ========
Substantially all of the Company's regulatory assets are being recovered through rates charged to customers. The Company expects to seek regulatory approval to recover any remaining regulatory assets in its next general rate case.
ENVIRONMENTAL COST RECOVERY. On April 6, 1995, in response to an application filed by the Company, the Commission approved, with modifications, an environmental cost recovery surcharge that increased electric revenues by $3.2 million in 1995 and $2.4 million in 1996. The surcharge became effective May 1, 1995.
An appeal of the Commission's April 6 order by various intervenors in the proceeding (including the Kentucky Attorney General) is currently pending in the Franklin Circuit Court of Kentucky. The Company is contesting the legal challenges to the surcharge, but cannot predict the outcome of the appeal. The amount of refunds that may be ordered, if any, are not expected to have a material adverse effect on the Company's financial position or results of operations. See Rates and Regulation under Management's Discussion and Analysis under Item 7 for a further discussion.
NOTE 3 - NON-RECURRING CHARGES
As part of a study of LG&E Energy Corp.'s business strategy and realignment during 1994, the Company re-evaluated its regulatory strategy which previously had been to seek full recovery of certain costs deferred in accordance with prior precedents established by the Commission. As a result of this re-evaluation, the Company wrote off certain expenses that had previously been deferred amounting to approximately $38.6 million before taxes. While the Company continues to believe that it could have reasonably expected to recover these costs in future rate proceedings before the Commission, the Company decided to deduct these expenses currently and not seek recovery for such expenses in future rates due to increasing competitive pressures and the existing and anticipated future economic conditions.
In the first quarter of 1994, the Board of Directors of the Company approved the formation of a tax-exempt charitable foundation (Foundation) that makes charitable contributions to qualified persons and entities. In 1994, the Company recorded a pre-tax charge against income and made an irrevocable payment of $15 million to fund the Foundation. The Foundation is exempt from federal income tax under the Internal Revenue Code.
NOTE 4 - FINANCIAL INSTRUMENTS
The Company uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt, and it uses exchange-traded U.S. Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies.
At December 31, 1996, the Company had a short position in U.S. Treasury note and bond futures contracts with notional amounts totaling $1.3 million. These contracts are used to hedge price risk associated with certain marketable securities and mature in March 1997.
At December 31, 1996, the Company was a party to two interest-rate swap agreements. The swaps have notional amounts of $15 million each, and the Company uses them to hedge its exposure to changes in the interest rates paid on $30 million of the Company's Pollution Control Bonds, Variable Rate Series, due September 1, 2017. One of these swaps will mature in September 1997, and the other will mature in September 1999. The Company paid interest at average fixed rates on the swaps of 4.55% in 1996, 1995, and 1994, and received interest at average variable rates based on the JJ Kenny Index of 3.46% in 1996, 3.87% in 1995, and 2.84% in 1994.
The cost and estimated fair values of the Company's financial instruments as of December 31, 1996 and 1995 follow (in thousands of $):
All of the above valuations reflect prices quoted by exchanges except for the swaps and the long-term investments. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models. The fair values of the long-term investments reflect cost, since the Company cannot reasonably estimate fair value.
NOTE 5 - CONCENTRATIONS OF CREDIT AND OTHER RISK
Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties (See Note 4, Financial Instruments, for further discussion) failed completely to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.
The Company's customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 277,000 customers and electricity to approximately 351,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 1996, 74% of total revenue was derived from electric operations and 26% from gas operations.
The Company's operation and maintenance employees are members of the International Brotherhood of Electrical Workers (IBEW) Local 2100 which represents approximately one-half of the Company's workforce. The Company's collective bargaining agreement with IBEW employees expires in November 1998.
NOTE 6 - MARKETABLE SECURITIES
The Company's marketable securities have been determined to be "available-for-sale" under the provisions of Statement of Financial Accounting Standards SFAS No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES. The available-for-sale category of investments results in the classification of unrealized gains and losses on investments in common equity, net of income taxes, until such gains and losses are realized, at which time they are recognized in earnings. Proceeds from sales of available-for-sale securities in 1996 were $28.6 million, which resulted in realized gains of $.3 million and losses of $.8 million, calculated using the specific identification method. Proceeds from sales of available-for-sale securities in 1995 were $151.4 million, which resulted in realized gains of $1.6 million and losses of approximately $3.4 million.
Approximate cost, fair value, and other required information about the Company's available-for-sale securities by major security type as of December 31, 1996 and 1995, follow (in thousands of $):
NOTE 7 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS. The Company has two non-contributory, defined-benefit pension plans, that cover all eligible employees. Retirement benefits are based on the employee's years of service, age at retirement 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. The assets of the plans consist primarily of common stocks, corporate bonds and United States government securities.
The Company also 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 in the preceding paragraph.
Pension costs were $4.3 million for 1996, $5 million for 1995, and $4.4 million for 1994, of which approximately $751,000, $761,000, and $693,000, respectively, were charged to construction. The components of periodic pension expense are shown below (in thousands of $):
1996 1995 1994 -------- -------- --------
Service cost-benefits earned during the period $ 4,989 $ 4,361 $ 4,813 Interest cost on projected benefit obligation . 16,697 14,328 13,057 Actual return on plan assets .................. (31,931) (45,608) (489) Amortization of transition asset .............. (1,112) (1,112) (1,112) Net amortization and deferral ................. 15,669 33,008 (11,846) -------- -------- -------- Net pension cost .............................. $ 4,312 $ 4,977 $ 4,423 ======== ======== ========
The funded status of the pension plans at December 31 is shown below (in thousands of $):
1996 1995 --------- --------- Actuarial present value of accumulated plan benefits: Vested ............................................... $ 178,534 $ 166,525 Non-Vested ........................................... 19,913 8,577 --------- ---------
Accumulated benefit obligation ....................... 198,447 175,102 Effect of projected future compensation .............. 30,902 31,764 --------- ---------
Projected benefit obligation ......................... 229,349 206,866 Plan assets at fair value ............................ 238,026 207,470 --------- ---------
Plan assets in excess of projected benefit obligation ................................. 8,677 604 Unrecognized net transition asset .................... (10,300) (11,412) Unrecognized prior service cost ...................... 44,142 28,938 Unrecognized net gain ................................ (65,891) (43,652) --------- ---------
Accrued pension liability .............................. $ (23,372) $ (25,522) ========= =========
The assumptions used in determining the actuarial valuations are as follows:
1996 1995 ------- -------
Assumed discount rate to determine projected benefit obligation .................. 7.75% 7.5% Assumed long-term rate of return on plan assets ................................ 8.5% 8.5% Assumed annual rate of increase in future compensation levels .................... 2% - 4.25% 3.5% - 4%
POST-RETIREMENT BENEFITS. 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. The Company accrues for the expected cost of post-retirement benefits other than pensions during the employee's years of service with the Company. The discounted present value of the post-retirement benefit obligation at the date of adoption is being amortized over 20 years.
Post-retirement benefit costs are shown below (in thousands of $):
1996 1995 1994 ------ ------ ------ Service cost .................................. $ 773 $ 595 $ 621 Interest cost ................................. 2,976 2,706 2,386 Amortization of transition obligation ......... 1,337 1,337 1,337 Amortization of prior service cost ............ 328 -- -- ------ ------ ------
Post-retirement benefit cost .................. $5,414 $4,638 $4,344 ====== ====== ======
The accumulated post-retirement benefit obligation at December 31, is shown below (in thousands of $):
1996 1995 -------- -------- Retirees ............................................. $(18,568) $(19,965) Fully eligible active employees ...................... (4,808) (2,768) Other active employees ............................... (16,575) (15,082) -------- --------
Accumulated post-retirement benefit obligation ....... (39,951) (37,815) Plan assets at fair value ............................ 2,284 -- Unrecognized prior service cost ...................... 3,738 -- Unrecognized transition obligation ................... 21,390 22,727 Unrecognized net loss ................................ 493 3,480 -------- --------
Accrued post-retirement benefit liability ............ $(12,046) $(11,608) ======== ========
The accumulated post-retirement benefit obligation was determined using an assumed discount rate of 7.75% for 1996 and 7.5% for 1995. Assumed compensation increases for projected life insurance benefits for affected groups was 4% for 1996 and 1995. An assumed health care cost trend rate of 10% was assumed for 1996, gradually decreasing to 5% in eight years and thereafter.
A 1% increase in the assumed health care cost trend rate would increase the accumulated post-retirement benefit obligation by approximately $2 million and the annual service and interest cost by approximately $200,000. In 1996, the Company began funding certain liabilities for post-retirement benefits through a tax-deductible funding vehicle. The plan assets are being held in two voluntary employee benefit association (VEBA) trusts and are invested primarily in short-term United States government securities.
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. These costs were approximately $1.8 million for 1996 and 1995, and $1.7 million for 1994.
NOTE 8 - INCOME TAXES
Components of income tax expense are shown in the table below (in thousands of $):
1996 1995 1994 -------- -------- -------- Included in Operating Expenses: Current - Federal ........................... $ 33,823 $ 36,379 $ 35,552 - State .............................. 7,685 9,138 9,003 Deferred - Federal-net ...................... 19,161 4,021 (969) - State-net .......................... 6,587 2,728 955 Deferred investment tax credit .............. 409 -- -- Amortization of investment tax credit ....... (4,406) (4,742) (4,619) -------- -------- --------
Total ................................. $ 63,259 $ 47,524 $ 39,922 -------- -------- --------
Included in Other Income and (Deductions): Current - Federal .......................... $ 196 $ (555) $ (4,626) - State ............................ (96) (343) (1,277) Deferred - Federal-net ...................... 246 240 19 - State-net ........................ 61 60 1 -------- -------- --------
Total ................................. $ 407 $ (598) $ (5,883) -------- -------- --------
Total Income Tax Expense ...................... $ 63,666 $ 46,926 $ 34,039 ======== ======== ========
Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
1996 1995 -------- -------- Deferred Tax Liabilities: Depreciation and other plant-related items ............. $314,692 $297,929 Other liabilities ...................................... 14,864 7,714 -------- -------- 329,556 305,643 -------- -------- Deferred Tax Assets: Investment tax credit .................................. 32,305 33,919 Income taxes due to customers .......................... 31,195 32,363 Pension overfunding .................................... 7,860 9,075 Accrued expenses not currently deductible and other .... 16,515 25,470 -------- -------- 87,875 100,827 -------- --------
Net Deferred Income Tax Liability .................... $241,681 $204,816 ======== ========
A reconciliation of differences between the statutory U.S. federal income tax rate and the Company's effective income tax rate follows:
1996 1995 1994 ------ ------ ------ Statutory federal income tax rate ............. 35.0% 35.0% 35.0% State income taxes net of federal benefit ..... 5.4 5.8 5.9 Amortization of investment tax credit ......... (2.6) (3.6) (5.1) Other differences-net ......................... (.7) (1.1) (.5) ------ ------ ------
Effective Income Tax Rate ..................... 37.1% 36.1% 35.3% ====== ====== ======
NOTE 9 - OTHER INCOME AND DEDUCTIONS
Other income and deductions consisted of the following at December 31 (in thousands of $):
1996 1995 1994 ------- ------- -------
Interest and dividend income ............... $ 4,096 $ 5,732 $ 4,568 (Losses) gains on fixed asset disposal ..... (36) 1,090 1,427 Donations .................................. (150) (144) (1,015) Income taxes and other ..................... (2,990) (2,902) (2,529) ------- ------- -------
Total other income and deductions .......... $ 920 $ 3,776 $ 2,451 ======= ======= =======
NOTE 10 - PREFERRED STOCK
In December 1995, the Company redeemed the 858,128 outstanding shares of its 7.45% Cumulative Preferred Stock with a par value of $25 per share at a redemption price of $25.75 per share.
NOTE 11 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL 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 1997 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 October 1996, the Company issued $22.5 million of Jefferson County, Kentucky, and $27.5 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible Rate Series, due September 1, 2026. Interest rates for these bonds were 3.60% and 3.57%, respectively, as of December 31, 1996. In December 1996, the proceeds from the bonds were used to redeem the outstanding 7.25% Series of Jefferson County and Trimble County Pollution Control Bonds due December 1, 2016.
On June 1, 1996, the Company's First Mortgage Bonds, 5.625% Series of $16 million matured and were retired by the Company.
In April 1995, the Company issued $40 million of Jefferson County, Kentucky, Pollution Control Bonds, 5.90% Series, due April 15, 2023. The proceeds of the bonds were used to redeem the outstanding 9.25% Series of Pollution Control Bonds due July 1, 2015.
The Company's First Mortgage Bonds, 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, 1996. The Company has no cash sinking fund requirements.
NOTE 12 - NOTES PAYABLE
The Company had no notes payable at December 31, 1996, and 1995.
At December 31, 1996, the Company had unused lines of credit of $200 million, for which it pays commitment fees. The credit lines are scheduled to expire during the year 2001. Management expects to renegotiate these lines when they expire.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM. The Company had commitments in connection with its construction program aggregating approximately $7 million at December 31, 1996. Construction expenditures for the years 1997 and 1998 are estimated to total approximately $250 million.
OPERATING LEASE. The Company has an operating lease for its corporate office building that is scheduled to expire in June 2005. The Company's total expense in connection with this lease for 1996, 1995, and 1994, less amounts contributed by the parent company, was $1.9 million, $2 million, and $2.2 million, respectively. The future minimum annual lease payments under the lease agreement for years subsequent to December 31, 1996, are as follows (in thousands of $):
1997 ................................................... $ 2,850 1998 ................................................... 2,850 1999 ................................................... 2,850 2000 ................................................... 3,178 2001 ................................................... 3,507 Thereafter ............................................. 12,275 ------- Total ................................................ $27,510 =======
ENVIRONMENTAL. With the passage of the Clean Air Act Amendments of 1990 (the Act), the Company already complied with the stringent sulfur dioxide emission limits required by the year 2000 as it had previously installed scrubbers on all of its coal-fired generating units. Since then, as part of its ongoing construction program, the Company has spent $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the Act on the Company has been minimal. However, the Company is closely monitoring a number of significant regulatory developments. In November 1996, the United States Environmental Protection Agency (USEPA) announced its proposal to revise the
National Ambient Air Quality Standards for ozone and particulate matter. In November 1996, USEPA also announced its intent to direct certain states to address long range ozone transport from Midwest emission sources which allegedly contribute to ozone problems in the Northeast. While management is unable to predict the outcome or exact impact of these ongoing regulatory proceedings, the Company continues to be 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 recent years, the Company has undertaken extensive modifications at its Mill Creek plant aimed at controlling certain particulate emissions which allegedly damaged metal surfaces on adjacent properties. The Air Pollution Control District of Jefferson County (APCD) and the Company are reviewing the results of a field sampling program to demonstrate the effectiveness of the plant modifications. In an effort to resolve the associated property damage claims, the Company also established a claims resolution process which resulted in property damage settlements with adjacent residents at an aggregate cost of approximately $15 million.
In August 1993, 34 persons filed a complaint in Jefferson Circuit Court against the Company seeking certification of a class consisting of certain persons in the vicinity of the Mill Creek plant who have allegedly suffered personal injury or property damage as a result of emissions from the plant. The court denied the Plaintiffs' initial motion for class certification, but allowed the Plaintiffs to bring a total of 537 individual claimants into the litigation. As part of its ongoing claims resolution process, as described above, the Company subsequently settled the claims of approximately half of the individual claimants. In December 1996, the court granted Plaintiff counsel's motion to withdraw from representation of all remaining claimants who have not settled with the Company. If those parties fail to obtain alternate counsel or otherwise pursue the litigation, their claims will be subject to dismissal. The Company intends to vigorously defend itself against any claims which remain. In management's opinion, resolution of any remaining claims should not have a material adverse impact on the financial position or results of operations of the Company.
In response to a notification from the APCD that the Company's Cane Run plant may be the source of a potential exceedance of the National Ambient Air Quality Standards for sulfur dioxide, the Company submitted a draft action plan and modeling schedule to the APCD and USEPA. The APCD and USEPA have approved the submittals, and a Company contractor is currently conducting additional modeling activities. Although it is expected that corrective action will be accomplished through capital improvements, until the modeling activities are complete, the Company cannot determine the precise impact of this matter.
The APCD is reviewing potential reductions in emissions of ozone precursors necessary to bring Jefferson County, Kentucky into compliance with the National Ambient Air Quality Standards for ozone. As described above, the Company has installed controls which result in substantial reductions in nitrogen oxide (NOX) emissions from its plants. In March 1994, the APCD adopted a regulation requiring a 15% reduction in volatile organic compound (VOC) emissions from industrial sources, including the Company's Cane Run and Mill Creek plants. Because there are currently no demonstrated technologies for control of VOC emissions from coal-fired boilers, the regulation raised the prospect of potential limits on generation at those two plants. After extensive negotiation with affected parties, in December 1996, the APCD amended its regulation to delete the requirement for VOC reductions from the Company's plants. The APCD also determined that no additional reductions in either industrial VOC or NOX
emissions are warranted at this time, but reserved the right to impose additional reductions if necessary in the future.
The Company owns or formerly owned three primary sites where manufactured gas plant operations were conducted. Remedial investigations performed at these sites have identified coal tar and other contaminants typical of manufactured gas plant operations. In December 1996, the Company conveyed one of the sites to a new owner for a nominal sum in return for the new owner assuming certain environmental liabilities and cleanup obligations. The Company does not expect to incur any further remedial investigation or cleanup costs at this site. The Company is awaiting regulatory determinations from the Kentucky Natural Resources and Environmental Protection Cabinet on the level of remediation required at both other sites. Until such regulatory determinations are made, the Company is unable to precisely determine the liability for cleanup costs. However, based on the results of studies at the sites, management currently estimates total cleanup costs will fall within a range of $3 million to $8 million and has recorded an accrual of approximately $3 million in the accompanying financial statements.
The Company, along with a number of other companies, has been identified as a potentially responsible party (PRP) allegedly liable for cleanup under the Comprehensive Environmental Response Compensation and Liability Act, as amended, at four off-site waste treatment or disposal sites. Under the law, each PRP potentially could be held jointly and severally liable for the cost of cleanup, but would have the right to seek contribution from other PRPs. The sites targeted for cleanup in which the Company has been identified as a PRP include the Smith's Farm site located in Bullitt County, Kentucky, the Sonora and Carlie Middleton Burn sites located in Hardin County, Kentucky, and the M.T. Richards site located in Crossville, Illinois. With respect to the Smith's Farm site, USEPA has identified the Company as a de minimis PRP and is currently pursuing other parties for the vast majority of the $44 million in cleanup costs as estimated by USEPA. The Company is participating in settlement discussions in an effort to resolve any alleged liability which it may have. With respect to the Sonora site and Carlie Middleton Burn site, the Company is involved in litigation with USEPA and approximately 50 companies in an effort to resolve liability for approximately $2.5 million in cleanup costs incurred by USEPA. With respect to the M.T. Richards site, the Company has been identified as a de minimis party and has reached a tentative settlement for $7,500, subject to approval by the government and entry by the court. While it is not possible at this time to predict the exact outcome or precise impact of these matters, management believes that these matters should not have a material adverse impact on the financial position or results of operations of the Company.
NOTE 14 - TRIMBLE COUNTY GENERATING PLANT
Trimble County Unit 1 (Trimble County), a 495-megawatt coal-fired electric generating unit placed into service in December 1990, has been the subject of numerous legal and regulatory proceedings to determine the appropriate ratemaking treatment to implement the Kentucky Public Service Commission's 1988 decision that the Company should not be allowed to recover 25% of the cost of Trimble County from ratepayers.
On December 1, 1995, the Company and other parties filed with the Commission a unanimous settlement agreement that was approved by the Commission on December 8, 1995. Under the agreement, which resolves all outstanding issues, the Company agreed to refund approximately $22 million to current electric customers, most of which is being refunded by credits to customers' bills over the five years 1996 through 2000. In addition, the Company has agreed to pay $900,000 per year for five years beginning in 1996 to the Metro Human Needs Alliance, Inc., a not-for-profit Louisville-based corporation, for the sole purpose of funding low-income energy assistance programs in the service territory. The Company also agreed to revise the residential decoupling methodology approved by the Commission in 1994 in a manner that will reduce revenues collected from residential customers during 1996 and 1997 by a total of approximately $1.8 million. Finally, the parties agreed to dismiss all appeals currently pending in state courts regarding the Commission's orders in the Company's last general rate case.
NOTE 15 - JOINTLY OWNED ELECTRIC UTILITY PLANT
The Company owns a 75% undivided interest in Trimble County Unit 1. Accounting for the 75% portion of the Unit, which the Commission has allowed to be reflected in customer rates, is similar to the Company's accounting for other wholly-owned utility plants.
Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA) owns a 12.12% undivided interest in the Unit, and Indiana Municipal Power Agency (IMPA) owns a 12.88% undivided interest. Each is responsible for their proportionate ownership share of operation and maintenance expenses and incremental assets, and for fuel used.
The following data represent shares of the jointly owned property:
Trimble County -------------------------------------- LG&E IMPA IMEA Total ---- ---- ---- ----- Ownership interest....... 75% 12.88% 12.12% 100% Mw capacity.............. 371.25 63.75 60 495
NOTE 16 - SEGMENTS OF BUSINESS
The Company is a regulated public utility engaged in the generation, transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas.
1996 1995 1994 ---------- ---------- ---------- (Thousands of $) Operating Information Operating Revenues Electric ............................. $ 606,696 $ 542,337(a) $ 558,946 Gas .................................. 214,419 181,126 200,129 ---------- ---------- ---------- Total .............................. $ 821,115 $ 723,463 $ 759,075 ========== ========== ==========
Pre-tax Operating Income Electric ............................. $ 192,129 $ 152,199 $ 139,594 Gas .................................. 18,393 16,651 11,368 ---------- ---------- ---------- Total .............................. $ 210,522 $ 168,850 $ 150,962 ========== ========== ==========
Other Information Depreciation and Amortization Electric ............................. $ 76,929 $ 74,437 $ 71,882 Gas .................................. 12,073 11,322 10,637 ---------- ---------- ---------- Total .............................. $ 89,002 $ 85,759 $ 82,519 ========== ========== ==========
Construction Expenditures (b) Electric ............................. $ 79,541 $ 66,661 $ 71,592 Gas .................................. 28,338 26,762 23,806 ---------- ---------- ---------- Total .............................. $ 107,879 $ 93,423 $ 95,398 ========== ========== ==========
Investment Information-December 31 Identifiable Assets Electric ............................. $1,505,508 $1,501,568 $1,514,287 Gas .................................. 300,550 268,840 252,946 ---------- ---------- ---------- Total .............................. 1,806,058 1,770,408 1,767,233 Other Assets (c) ...................... 200,654 209,082 199,357 ---------- ---------- ---------- Total Assets ....................... $2,006,712 $1,979,490 $1,966,590 ========== ========== ==========
(a) Net of Refund - Trimble County Settlement of $28.3 million. (b) Excluding cost of removal and salvage. (c) Includes cash and temporary cash investments, marketable securities, 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 LLP, independent public accountants. Management has made available to Arthur Andersen LLP all the Company's financial records and related data as well as the minutes of shareholders' and directors' meetings.
Management has established and maintains a system of internal controls that provide reasonable assurance that transactions are completed in accordance with management's authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by the Company's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal auditors. These recommendations for the year ended December 31, 1996, did not identify any material weaknesses 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, 1996 and 1995, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1996. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP January 29, 1997 ----------------------------- Arthur Andersen LLP
---------------------------
SELECTED QUARTERLY FINANCIAL DATA (Unaudited) (Thousands of $)
Selected financial data for the four quarters of 1996 and 1995 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
Quarters Ended ------------------------------------------- March June September December ----- ---- --------- -------- Operating Revenues .............. $226,744 $181,107 $203,818 $209,446 Net Operating Income ............ 33,950 32,736 51,681 28,896 Net Income ...................... 23,552 22,908 42,466 19,015 Net Income Available for Common Stock .................. 22,396 21,772 41,320 17,885
Operating Revenues .............. $199,517 $167,821 $196,351 $159,774(a) Net Operating Income ............ 32,409 30,015 47,774 11,128 Net Income ...................... 21,839 21,085 38,346 1,914 Net Income Available for Common Stock .................. 20,222 19,458 36,780 413
(a) Net of Refund - Trimble County Settlement of $28.3 million.
-------------------------
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 26, 1997, 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 10 relating to executive officers has been included in Part I of this Form 10-K. The Louisville Gas and Electric Company (LG&E) is a subsidiary of LG&E Energy Corp. At December 31, 1996, LG&E Energy Corp. controlled 100% of the common stock of LG&E. There are situations where LG&E Energy Corp. interacts with its affiliated companies through the use of shared facilities, common employees, and other business relationships. In these situations, LG&E receives payment in accordance with regulatory requirements for the services provided to affiliated companies.
PART IV
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, 1996 (page 24). Statements of Retained Earnings for the three years ended December 31, 1996 (page 24). Statements of Cash Flows for the three years ended December 31, 1996 (page 25). Balance Sheets - December 31, 1996, and 1995 (page 26). Statements of Capitalization - December 31, 1996, and 1995 (page 27). Notes to Financial Statements (pages 28-42). Report of Management (page 43). Report of Independent Public Accountants (page 44). Selected Quarterly Financial Data for 1996 and 1995 (page 45).
2. Financial Statement Schedule (included in Part IV): Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 1996 (page 62).
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, dated November 6, 1996. [Filed as Exhibit 3.06 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein]
3.02 Copy of Bylaws, as amended through December 15, 1995. [Filed as Exhibit 3.06 to the Company's Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
4.01 Copy of Trust Indenture dated November 1, 1949, from the Company to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to Registration Statement 2-8283 and incorporated by reference herein]
4.02 Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.05 to Registration Statement 2-9371 and incorporated by reference herein]
4.03 Copy of Supplemental Indenture dated February 1, 1954, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.03 to Registration Statement 2-11923 and incorporated by reference herein]
4.04 Copy of Supplemental Indenture dated September 1, 1957, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.04 to Registration Statement 2-17047 and incorporated by reference herein]
4.05 Copy of Supplemental Indenture dated October 1, 1960, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.05 to Registration Statement 2-24920 and incorporated by reference herein]
4.06 Copy of Supplemental Indenture dated June 1, 1966, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.06 to Registration Statement 2-28865 and incorporated by reference herein]
4.07 Copy of Supplemental Indenture dated June 1, 1968, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.07 to Registration Statement 2-37368 and incorporated by reference herein]
4.08 Copy of Supplemental Indenture dated June 1, 1970, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.08 to Registration Statement 2-37368 and incorporated by reference herein]
4.09 Copy of Supplemental Indenture dated August 1, 1971, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.09 to Registration Statement 2-44295 and incorporated by reference herein]
4.10 Copy of Supplemental Indenture dated June 1, 1972, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.10 to Registration Statement 2-52643 and incorporated by reference herein]
4.11 Copy of Supplemental Indenture dated February 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.11 to Registration Statement 2-57252 and incorporated by reference herein]
4.12 Copy of Supplemental Indenture dated September 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.12 to Registration Statement 2-57252 and incorporated by reference herein]
4.13 Copy of Supplemental Indenture dated September 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.13 to Registration Statement 2-57252 and incorporated by reference herein]
4.14 Copy of Supplemental Indenture dated October 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.14 to Registration Statement 2-65271 and incorporated by reference herein]
4.15 Copy of Supplemental Indenture dated June 1, 1978, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.15 to Registration Statement 2-65271 and incorporated by reference herein]
4.16 Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.16 to Registration Statement 2-65271 and incorporated by reference herein]
4.17 Copy of Supplemental Indenture dated September 1, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.18 Copy of Supplemental Indenture dated September 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.19 Copy of Supplemental Indenture dated September 15, 1981, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
4.20 Copy of Supplemental Indenture dated March 1, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.20 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.21 Copy of Supplemental Indenture dated March 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.22 Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.23 Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.23 to the Company's Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein]
4.24 Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein]
4.25 Copy of Supplemental Indenture dated November 15, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.26 Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.27 Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein]
4.28 Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.29 Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.30 Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.31 Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.32 Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.33 Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.34 Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.35 Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.36 Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.01 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]
10.02 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]
10.03 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 5.02(c) to Registration Statement 2-61607 and incorporated by reference herein]
10.04 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]
10.05 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]
10.06 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 5.02(f) to Registration Statement 2-61607 and incorporated by reference herein]
10.07 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]
10.08 Copies of Amendments to Agreements (iii) and (iv) referred to under 10.06 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02(h) to Registration Statement 2-61607 and incorporated by reference herein]
10.09 Copy of Modification No. 1, dated August 20, 1958, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02(i) to Registration Statement 2-61607 and incorporated by reference herein]
10.10 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 5.02(j) to Registration Statement 2-6l607 and incorporated by reference herein]
10.11 Copy of Modification No. 3, dated January 20, 1967, to the 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]
10.12 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]
10.13 Copy of Modification No. 3, dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02(m) to Registration Statement 2-37368 and incorporated by reference herein]
10.14 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 5.02(n) to Registration Statement 2-56357 and incorporated by reference herein]
10.15 Copy of Modification No. 4, dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02(o) to Registration Statement 2-56357 and incorporated by reference herein]
10.16 Copy of Modification No. 4, dated April 30, 1976, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02(p) to Registration Statement 2-6l607 and incorporated by reference herein]
10.17 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 5.02(q) to Registration Statement 2-61607 and incorporated by reference herein]
10.18 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 5.02(r) to Registration Statement 2-63149 and incorporated by reference herein]
10.19 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]
10.20 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]
10.21 Copy of Modification No. 5, dated September 1, 1979, to the 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]
10.22 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]
10.23 Copy of Modification No. 6, dated August 1, 1981, to the 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]
10.24 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]
10.25 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]
10.26 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]
10.27 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]
10.28 Copy of Supplemental Executive Retirement Plan for Roger W. Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.29 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]
10.30 Copy of Modification No. 13, dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.31 Copy of Modification No. 14, dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.32 Copy of Modification No. 7, dated January 15, 1992, to the Inter- Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.33 Copy of Modification No. 15, dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.34 Copy of Firm No-Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (expires October 31, 2001) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
Copy of Firm No-Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (expires October 31, 2000) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
Copy of Firm No-Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (expires October 31, 1998) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.35 Copy of Employment Contract between LG&E Energy Corp. and Roger W. Hale effective January 1, 1997. [Filed as Exhibit 10.70 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.36 Copy of LG&E Energy Corp. Stock Option Plan for Non-Employee Directors. [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.37 Copy of Modification No. 8 dated January 19, 1994, to Intercompany Power Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.38 Copy of Amendment dated March 1, 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and 8-Year), between Texas Gas Transmission Corporation and LG&E covering the transmission of natural gas. [Filed as Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.39 Copy of Modification No. 9, dated August 17, 1995, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.
10.40 Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and the Company (expires October 31, 1998) covering the transportation of natural gas. [Filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and the Company (expires October 31, 2001) covering the transportation of natural gas. [Filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.41 Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and the Company (expires October 31, 2000) covering the transportation of natural gas.
10.42 Copy of Firm Transportation Agreement, dated November 1, 1996, between Tennessee Gas Pipeline Company and the Company (expires October 31, 2001) covering the transportation of natural gas.
10.43 Copy of Coal Supply Agreement, dated January 1, 1996, between Lafayette Coal Company, Black Beauty Coal Company and the Company covering the purchase of coal. [Filed as Exhibit 10.46 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.44 Copy of Coal Supply Agreement, dated December 15, 1995, between W. B. Coal Company, Inc., Windsor Coal Company and the Company covering the purchase of coal. [Filed as Exhibit 10.48 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.45 Copy of Coal Supply Agreement dated January 1, 1996, between Peabody Coalsales Company and the Company covering the purchase of coal. [Filed as Exhibit 10.49 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.46 Copy of Coal Supply Agreement dated June 1, 1996, between Kindill Mining, Inc. and the Company covering the purchase of coal.
10.47 Copy of Amendment dated October 31, 1996, to the Coal Supply Agreement dated June 1, 1996, between Kindill Mining, Inc. and the Company covering the purchase of coal.
10.48 Copy of Amended and Restated Omnibus Long-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.52 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.49 Copy of Short-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.53 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.50 Copy of form of first amendment to change in control agreement for officers of the Company and key employees. [Filed as Exhibit 10.54 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.51 Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.52 Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.53 Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.54 Copy of Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1992. [Filed as Exhibit 10.58 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.55 Copy of Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1993. [Filed as Exhibit 10.59 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.56 Copy of Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1995. [Filed as Exhibit 10.60 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.57 Copy of Amendment to the Supplemental Executive Retirement Plan, effective May 1, 1995. [Filed as Exhibit 10.61 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.58 Copy of Credit Agreement, dated December 18, 1995, by and among the Company the Banks party thereto, PNC Bank, Kentucky, Inc. as Agent and Bank of Montreal as Co-Agent. [Filed as Exhibit 10.01 to the Company's Quarterly Report on Form 10-Q/A for the quarter ended March 31, 1996, and incorporated by reference herein]
10.59 Copy of Amendment No. 1, dated as of November 5, 1996, to the Credit Agreement dated December 18, 1995, by and among the Company, the Banks party thereto, and PNC Bank, Kentucky, Inc. as agent for the banks.
12 Computation of Ratio of Earnings to Fixed Charges
23 Consent of Independent Public Accountants
24 Power of Attorney
27 Financial Data Schedule
99.01 Cautionary Statement for purposes of the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995.
(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]
LG&E Energy Corp. Deferred Stock Compensation Plan effective January 1, 1992, covering non-employee directors of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein]
Form of change in control agreement for officers of Louisville Gas and Electric Company. [Filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
Supplemental Executive Retirement Plan for R. W. Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
Nonqualified Savings Plan covering officers of the Company effective January 1, 1992. [Filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
Employment Contract between LG&E Energy Corp. and Roger W. Hale effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
Employment Contract between LG&E Energy Corp. and Roger W. Hale effective January 1, 1997. [Filed as Exhibit 10.70 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1996, 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]
Amended and Restated Omnibus Long-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.52 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Short-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.53 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Form of first amendment to change in control agreement for officers of the Company and key employees. [Filed as Exhibit 10.54 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1992. [Filed as Exhibit 10.58 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1993. [Filed as Exhibit 10.59 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1995. [Filed as Exhibit 10.60 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective May 1, 1995. [Filed as Exhibit 10.61 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Non-Officer Senior Management Pension Restoration Plan, effective May 1, 1996 [Filed as Exhibit 10.69 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
(c) Reports on Form 8-K:
None.
SCHEDULE II
LOUISVILLE GAS AND ELECTRIC COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 1996 (Thousands of $)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. LOUISVILLE GAS AND ELECTRIC COMPANY Registrant
March 25, 1997 By /s/ M. L. FOWLER - -------------- ---------------------------------------- (Date) M. L. Fowler Vice President and Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date --------- ----- ---- ROGER W. HALE Chairman of the Board and Chief Executive Officer (Principal Executive Officer);
CHARLES A. MARKEL III Treasurer (Principal Financial Officer);
M. L. FOWLER Vice President and Controller (Principal Accounting Officer);
WILLIAM C. BALLARD, JR. Director;
RONALD L. BITTNER Director;
OWSLEY BROWN II Director;
S. GORDON DABNEY Director;
GENE P. GARDNER Director;
J. DAVID GRISSOM Director;
DAVID B. LEWIS Director;
ANNE H. MCNAMARA Director;
T. BALLARD MORTON, JR. Director; and
DR. DONALD C. SWAIN Director.
By /s/ M. L. FOWLER ------------------------------- March 25, 1997 M. L. FOWLER (Attorney-In-Fact)