-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, GzfpLs0SdMmXGENGnHUXbsuETz9Nbh5oqsEozXehBMaKc8Edl69pHdom0gzmRLoQ AGoHcRYmMGDdDqnJV9Y5iQ== 0000912057-97-010845.txt : 19970329 0000912057-97-010845.hdr.sgml : 19970329 ACCESSION NUMBER: 0000912057-97-010845 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: LOUISVILLE GAS & ELECTRIC CO /KY/ CENTRAL INDEX KEY: 0000060549 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 610264150 STATE OF INCORPORATION: KY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-02893 FILM NUMBER: 97567994 BUSINESS ADDRESS: STREET 1: 220 W MAIN ST STREET 2: P O BOX 32010 CITY: LOUISVILLE STATE: KY ZIP: 40232 BUSINESS PHONE: 5026272000 MAIL ADDRESS: STREET 1: 220 WEST MAIN ST CITY: LUUISVILLE STATE: KY ZIP: 40232 10-K405 1 10-K405 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 ------------------ FORM 10-K |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the fiscal year ended December 31, 1996 OR |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) Commission File No. 2-26720 - -------------------------------------------------------------------------------- LOUISVILLE GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) - -------------------------------------------------------------------------------- KENTUCKY 61-0264150 (State or other jurisdiction of (I.R.S.Employer incorporation or organization) Identification No.) 220 W. Main Street P. O. Box 32010 (502) 627-2000 Louisville, Kentucky 40232 (Registrant's telephone (Address of principal executive offices number, including area code) Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered ------------------- ------------------------ First Mortgage Bonds, Series due July 1, 2002, 7 1/2% New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: 5% Cumulative Preferred Stock, $25 Par Value $5.875 Cumulative Preferred Stock, Without Par Value Auction Rate Series A Preferred Stock, Without Par Value (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X|. No |_|. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| As of February 28, 1997, the aggregate market value of the registrant's voting stock held by non-affiliates was $15,162,170 and the number of outstanding shares of the registrant's common stock, without par value, was 21,294,223 all of which were held by LG&E Energy Corp. DOCUMENTS INCORPORATED BY REFERENCE The proxy statement of Louisville Gas and Electric Company filed with the Commission on March 26, 1997, is incorporated by reference into Part III of this Form 10-K. TABLE OF CONTENTS PART I PAGE ---- Item 1. Business................................................... 1 General.................................................. 1 Electric Operations...................................... 3 Gas Operations........................................... 5 Regulation and Rates..................................... 6 Construction Program and Financing....................... 7 Coal Supply.............................................. 7 Gas Supply............................................... 8 Environmental Matters.................................... 9 Labor Relations.......................................... 10 Employees................................................ 10 Item 2. Properties................................................. 11 Item 3. Legal Proceedings.......................................... 12 Item 4. Submission of Matters to a Vote of Security Holders........ 13 Executive Officers of the Company................................... 13 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters...................................... 15 Item 6. Selected Financial Data.................................... 15 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition....................... 16 Item 8. Financial Statements and Supplementary Data................ 24 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................. 45 PART III Item 10. Directors and Executive Officers of the Registrant (a)..... 46 Item 11. Executive Compensation (a)................................. 46 Item 12. Security Ownership of Certain Beneficial Owners and Management (a)....................................... 46 Item 13. Certain Relationships and Related Transactions (a)......... 46 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................................. 46 Signatures ......................................................... 63 (a) Incorporated by reference. PART I 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 -1- 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. -2- 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. -3- 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. -4- 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. -5- 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. -6- 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. -7- 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. -8- 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. -9- 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. -10- 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. -11- 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. 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. -12- 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 -13- 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. -14- PART II 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. SELECTED FINANCIAL DATA.
Years Ended December 31 -------------------------------------------------------------- 1996 1995 1994 1993 1992 ---------- ----------- ----------- ---------- ---------- Operating Revenues .................... $ 821,115 $ 723,463 $ 759,075 $ 775,125 $ 700,195 ---------- ----------- ----------- ---------- ---------- Net Operating Income: Before Unusual Items ............... 147,263 138,203 134,393 136,118 125,829 Trimble County Settlement .......... -- (16,877) -- -- -- Non-Recurring Charges .............. -- -- (23,353) -- -- ---------- ----------- ----------- ---------- ---------- Total Net Operating Income ...... 147,263 121,326 111,040 136,118 125,829 ---------- ----------- ----------- ---------- ---------- Net Income: Before Unusual Items ............... 107,941 100,061 94,423 90,535 73,793 Trimble County Settlement .......... -- (16,877) -- -- -- Non-Recurring Charges, Charitable Foundation, etc....... -- -- (32,734) -- -- Cumulative Effect of Accounting Change ............... -- -- (3,369) -- -- ---------- ----------- ----------- ---------- ---------- Total Net Income ................ 107,941 83,184 58,320 90,535 73,793 ---------- ----------- ----------- ---------- ---------- Net Income Available for Common Stock ........................ 103,373 76,873 52,492 84,554 66,620 ---------- ----------- ----------- ---------- ---------- Total Assets .......................... 2,006,712 1,979,490 1,966,590 1,974,584 1,960,860 Long-Term Obligations (including amounts due within one year) ........ 646,800 662,800 662,800 662,800 686,262
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. -15- 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. -16- 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 $):
Increase (Decrease) From Prior Period ----------------------------------------- Electric Revenues Gas Revenues ------------------- ------------------- Cause 1996 1995 1996 1995 ----- ---- ---- ---- ---- Sales to Ultimate Consumers: Fuel and gas supply adjustments, etc $ (4,652) $(10,566) $ 21,176 $(16,940) Demand side management/decoupling ... 5,429 (4,619) (1,989) 479 Environmental cost recovery surcharge 2,410 3,205 -- -- Variation in sales volumes .......... 801 27,382 14,483 (3,420) -------- -------- -------- -------- Total ............................. 3,988 15,402 33,670 (19,881) Sales for resale ........................ 30,383 (5,249) -- -- Gas transportation-net .................. -- -- (971) 1,062 Other ................................... 1,688 1,538 594 (184) -------- -------- -------- -------- Total ............................. $ 36,059 $ 11,691 $ 33,293 $(19,003) ======== ======== ======== ========
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 -17- 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. Depreciation and amortization increased in both 1996 and 1995 primarily because of additional depreciable plant in service. Variations in income tax expenses are largely attributable to changes in pre-tax income. Other income decreased about $3 million in 1996 because of a decrease in income earned from investments and lower gains realized from the sale of property as compared to 1995. See Note 9 of Notes to Financial Statements under Item 8. Contribution to the Company's charitable foundation reflects the expense associated with establishing a tax-exempt foundation during 1994. Contributions made from this Foundation are not charged against income, and therefore, do not affect the Company's net income. See Note 3 of Notes to Financial Statements under Item 8. -18- Interest charges for 1996 decreased $1.7 million (4%) primarily because of the retirement of outstanding debt. The Company's First Mortgage Bonds, 5.625% Series of $16 million were retired at maturity on June 1, 1996 and $50 million in other debt was refinanced at more favorable rates. Interest charges for 1995 decreased $.9 million primarily due to a reversal of an interest expense reserve resulting from a favorable ruling on certain income tax matters. The embedded cost of long-term debt at December 31, 1996, was 6.05%; at December 31, 1995, 6.32%. See Note 11 under Item 8, First Mortgage Bonds and Pollution Control Bonds, for further discussion. Preferred dividends decreased $1.7 million (28%) due primarily to the redemption of the 7.45% Series Cumulative Preferred Stock in December 1995. Preferred dividends increased $.5 million in 1995 because of a higher rate associated with the Auction Rate Series. The rate of inflation may have a significant impact on the Company's operations, its ability to control costs, and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results. LIQUIDITY AND CAPITAL RESOURCES The Company's need for capital funds is primarily related to the construction of plant and equipment necessary to meet the needs of electric and gas utility customers and protection of the environment. Capital Requirements New construction expenditures for 1996 were $108 million compared with $93 million for 1995 and $95 million for 1994. Past Financing Activities During 1996, 1995, and 1994, the Company's primary source of capital was internally generated funds from operating cash flows. Internally generated funds provided financing for 100% of the Company's construction expenditures for 1996, 1995, and 1994. Variations in accounts receivable and accounts payable are not generally significant indicators of the Company's liquidity, as such variations are primarily attributable to fluctuations in weather in the Company's service territory, which has a direct affect on sales of electricity and natural gas. On June 1, 1996, the Company's First Mortgage Bonds, 5.625% Series of $16 million matured and were retired by the Company. The bonds were redeemed with available funds. 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, at December 31, 1996. The proceeds from these bonds were applied in December 1996 to redeem the outstanding 7.25% Series of Jefferson County, Kentucky and Trimble County, Kentucky, Pollution Control Bonds due December 1, 2016. -19- In April 1995, the Company issued $40 million of Jefferson County, Kentucky, Pollution Control Bonds, 5.90% Series, due April 15, 2023. The proceeds from these bonds were used to redeem the outstanding 9.25% Series of Pollution Control Bonds due July 1, 2015. In December 1995, the Company redeemed the 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. The Company funded the $22 million redemption with cash generated internally. Future Capital Requirements Future financing requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions allowed by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. The Company estimates construction expenditures will total $250 million for 1997 and 1998. In addition, capital requirements for 1998 include $20 million to retire long-term debt that is scheduled to mature. Future Sources of Financing Internally generated funds from operations are expected to fund substantially all anticipated construction expenditures in 1997 and 1998. At December 31, 1996, the Company had unused lines of credit of $200 million for which it pays commitment fees. These credit facilities are scheduled to expire during the year 2001. Management expects to renegotiate them when they expire. To the extent permanent financings are needed in 1997 and 1998, the Company expects that it will have ready access to the securities markets to raise needed funds. Year 2000 Computer Software Modification Costs Based on a preliminary study, the Company expects to spend approximately $12 million to $15 million from 1997 through 1999 to modify its computer information systems enabling proper processing of transactions relating to the year 2000 and beyond. The Company continues to evaluate appropriate courses of corrective action, including replacement of certain systems whose associated costs would be recorded as assets and amortized. Accordingly, the Company does not expect the amounts required to be expensed over the next three years to have a material effect on its financial position or results of operations. The amount expensed in 1996 was immaterial. -20- Rates and Regulation The Company is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, its accounting is subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Given the Company's competitive position in the market and the status of regulation in the state of Kentucky, the Company has no plans or intentions to discontinue its application of SFAS No. 71. See Note 2 of Notes to Financial Statements under Item 8. 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 plant costs from customer rates. Under the settlement, ratepayers are to receive $22 million in refunds, most of which is being refunded over the five-year period, 1996 through 2000, based on a per kilowatt-hour credit. In addition, the Company also agreed to provide $900,000 annually for five years, beginning in 1996, to fund low-income energy assistance programs and agreed to revise the decoupling methodology in a manner that was to reduce revenues collected from residential customers during 1996 and 1997 by a total of approximately $1.8 million. The overall effect of the settlement, which the Company recognized in its entirety in the fourth quarter of 1995, was to reduce electric revenues by $28.3 million and net income by $16.9 million. See Note 14 of Notes to Financial Statements under Item 8 for further discussion. In May 1995, the Company implemented a Commission approved environmental cost recovery (ECR) surcharge to recover certain costs required to comply with the Federal Clean Air Act, as amended, and those federal, state, and local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal. As a result of this surcharge, the Company's electric revenues increased $3.2 million in 1995, an additional $2.4 million in 1996 and a further increase in revenues of approximately $1 million is projected for 1997. The Kentucky Attorney General (KAG), and the Kentucky Industrial Utility Customers (KIUC) have filed an appeal in Franklin Circuit Court on various issues related to the Commission's order in this proceeding, including the constitutionality of the Kentucky statute that authorizes the surcharge. In an order dated April 10, 1996, associated with the first six-month review of the operation of the surcharge, the Commission stated that all environmental surcharge revenues collected from the date of the April 10 order will be subject to refund, pending the final determination of the April 6, 1995, order. The Company is contesting the legal challenges but cannot predict the outcome of this litigation. However, the amount of refunds, if any, that may ultimately be ordered, are not expected to have a material adverse effect on the Company's financial position or results of operation. In January 1994, the Company implemented a Commission approved demand side management (DSM) program that the Company, KAG, the Jefferson County Attorney, and representatives of several customer-interest groups had filed with the Commission. The Company committed up to $3.3 million over three years (from 1994 through 1996) for initial programs that include a residential energy conservation and education program and a commercial conservation audit program. The approved program includes a formal collaborative process to develop future DSM programs and also contains a rate mechanism that (1) provides the Company concurrent recovery of DSM costs, (2) provides an incentive for implementing DSM programs, and (3) allows the Company to recover revenues from lost sales associated with the DSM programs through a decoupling mechanism. -21- In 1996, the Commission approved the addition of six new programs that increased the Company's commitment to DSM by approximately $4 million over the next two years. 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. Order 889 requires public utilities to implement standards of conduct and an Open Access Same-time Information System (OASIS). The standards of conduct require that public utilities functionally separate their transmission and wholesale power merchant functions. OASIS will allow other parties to obtain information about a utility's transmission system in the same manner that the utility's wholesale power merchant function does. OASIS ensures that relevant information is passed from the utility's transmission function to the purchaser of transmission service in a non-discriminatory manner. The Company has made a functional separation of its transmission and wholesale power merchant function. A filing of the Company's standards of conduct was made with the FERC on December 31, 1996. In January 1997, the Company began operation of its OASIS system in accordance with the FERC Order. The Company last filed for a rate increase with the Commission in June 1990 based on the test-year ended April 30, 1990. The Commission issued a final order in September 1991 that effectively granted the Company an annual increase in rates of $6.8 million ($6.1 million electric and $.7 million gas). Environmental Matters 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. These expenditures are being recovered under the environmental cost recovery mechanism as more fully discussed in Note 2 of the Notes to Financial Statements under Item 8. 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, the 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. Reference is made to Environmental under Note 13 of Notes to Financial Statements under Item 8 for a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run electric generating plants, manufactured gas plant sites, and certain other environmental issues. -22- FUTURE OUTLOOK Electric Industry Restructuring The Kentucky Public Service Commission (Kentucky Commission) has held a series of meetings with electric utilities operating in Kentucky to discuss the potential impact of the major restructuring of the industry that is being driven by competition and market forces. Specifically, the Kentucky Commission has indicated it wants to ensure that ratepayers in Kentucky will continue to receive the current low electric rates and high reliability and quality of service during and after the restructuring of the industry. Topics discussed have included the regulatory treatment of potential stranded costs or benefits, the utility's historical obligation to serve, the functional separation of utilities, regulatory and legal changes that may be needed in a restructured electric industry and many other issues. These wide-ranging discussions, which are expected to continue in the future, centered around the theme of how the Kentucky Commission and utilities can best work together to benefit energy consumers in Kentucky. The Company is exploring steps that it can take to maintain or even improve its position as a low-cost producer of electricity and evaluating other actions, including an analysis associated with the future recovery of certain regulatory assets, that will enable the Company to continue to offer favorable electric rates to its customers. -23- Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Thousands of $)
Years Ended December 31 ------------------------------- 1996 1995 1994 -------- --------- --------- Operating Revenues Electric .......................................... $606,696 $ 570,637 $ 558,946 Gas ............................................... 214,419 181,126 200,129 Refund - Trimble County Settlement (Note 14) ...... -- (28,300) -- -------- --------- --------- Total operating revenues (Note 1) ................ 821,115 723,463 759,075 -------- --------- --------- Operating Expenses Fuel for electric generation ...................... 149,697 138,002 143,602 Power purchased ................................... 16,626 16,830 9,754 Gas supply expenses ............................... 140,482 110,738 131,561 Other operation expenses .......................... 143,338 134,655 136,214 Maintenance ....................................... 54,790 52,101 48,731 Non-recurring charges (Note 3) .................... -- -- 38,613 Depreciation and amortization ..................... 89,002 85,759 82,519 Federal and State income taxes (Note 8) ........... 63,259 47,524 39,922 Property and other taxes .......................... 16,658 16,528 17,119 -------- --------- --------- Total operating expenses ......................... 673,852 602,137 648,035 -------- --------- --------- Net Operating Income ................................ 147,263 121,326 111,040 Other Income and (Deductions) (Note 9) .............. 920 3,776 2,451 Contribution to Charitable Foundation - net (Note 3) -- -- 8,946 Interest Charges .................................... 40,242 41,918 42,856 -------- --------- --------- Income before Cumulative Effect of a Change in Accounting Principle .............................. 107,941 83,184 61,689 Cumulative Effect of a Change in Accounting for Post-Employment Benefits, net of income taxes of $2,280 ......................................... -- -- (3,369) -------- --------- --------- Net Income .......................................... 107,941 83,184 58,320 Preferred Stock Dividends ........................... 4,568 6,311 5,828 -------- --------- --------- Net Income Available for Common Stock ............... $103,373 $ 76,873 $ 52,492 ======== ========= =========
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. -24- LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Thousands of $)
Years Ended December 31 --------------------------------- 1996 1995 1994 --------- --------- --------- Cash Flows from Operating Activities Net Income ................................................... $ 107,941 $ 83,184 $ 58,320 Items not requiring cash currently: Depreciation and amortization ............................... 89,002 85,759 82,519 Deferred income taxes-net ................................... 26,055 7,049 (2,274) Investment tax credit-net ................................... (3,997) (4,742) (4,619) Cumulative effect of change in accounting principle ......... -- -- 3,369 Non-recurring charges ....................................... -- -- 38,613 Other ....................................................... 3,911 3,958 6,603 (Increases) decreases in certain net current assets: Accounts receivable ......................................... (9,555) (19,531) 18,339 Materials and supplies ...................................... (1,418) 1,428 3,280 Trimble County Settlement ................................... (10,789) 28,300 -- Accounts payable ............................................ 3,772 22,936 (22,781) Accrued taxes ............................................... 4,168 (433) (1,247) Accrued interest ............................................ (1,070) (2,330) 530 Prepayments and other ....................................... 685 (61) (743) Other ........................................................ (23,153) (6,917) 972 --------- --------- --------- Net cash provided by operating activities ................... 185,552 198,600 180,881 --------- --------- --------- Cash Flows from Investing Activities Purchases of securities ...................................... (11,039) (119,151) (87,896) Proceeds from sales of securities ............................ 28,605 151,422 56,085 Construction expenditures .................................... (107,879) (93,423) (95,398) --------- --------- --------- Net cash used for investing activities ...................... (90,313) (61,152) (127,209) --------- --------- --------- Cash Flows from Financing Activities Issuance of first mortgage bonds and pollution control bonds . 49,745 39,914 -- Redemption of preferred stock ................................ -- (22,108) -- Retirement of first mortgage bonds and pollution control bonds (67,013) (41,055) -- Payment of dividends ......................................... (79,310) (95,206) (58,639) --------- --------- --------- Net cash used for financing activities ...................... (96,578) (118,455) (58,639) --------- --------- --------- Net Increase (Decrease) in Cash and Temporary Cash Investments . (1,339) 18,993 (4,967) Cash and Temporary Cash Investments at Beginning of Year ....... 58,131 39,138 44,105 --------- --------- --------- Cash and Temporary Cash Investments at End of Year ............. $ 56,792 $ 58,131 $ 39,138 ========= ========= ========= Supplemental Disclosures of Cash Flow Information Cash paid during the year for: Income taxes ................................................ $ 41,508 $ 40,049 $ 42,803 Interest on borrowed money .................................. 40,334 42,589 40,827
The accompanying notes are an integral part of these financial statements. -25- LOUISVILLE GAS AND ELECTRIC COMPANY BALANCE SHEETS (Thousands of $)
Assets December 31 ---------------------- 1996 1995 ---------- ---------- Utility Plant, at original cost Electric ............................................... $2,192,557 $2,123,699 Gas .................................................... 320,791 299,070 Common ................................................. 130,678 128,902 ---------- ---------- 2,644,026 2,551,671 Less: Reserve for depreciation ........................ 999,987 934,942 ---------- ---------- 1,644,039 1,616,729 Construction work in progress .......................... 41,183 47,189 ---------- ---------- 1,685,222 1,663,918 ---------- ---------- Other Property and Investments - less reserve ............ 1,028 760 ---------- ---------- Current Assets Cash and temporary cash investments .................... 56,792 58,131 Marketable securities (Note 6) ......................... 3,595 20,449 Accounts receivable-less reserve of $1,470 in 1996 and $1,360 in 1995 ............................ 115,144 105,589 Materials and supplies-at average cost Fuel (predominantly coal) ............................. 14,576 14,996 Gas stored underground ................................ 35,510 31,714 Other ................................................. 32,426 34,384 Prepayments ............................................ 2,480 2,108 ---------- ---------- 260,523 267,371 ---------- ---------- Deferred Debits and Other Assets Unamortized debt expense ............................... 6,933 7,710 Regulatory assets (Note 2) ............................. 27,729 29,926 Other .................................................. 25,277 9,805 ---------- ---------- 59,939 47,441 ---------- ---------- $2,006,712 $1,979,490 ========== ========== Capital and Liabilities Capitalization (see Statements of Capitalization) Common equity .......................................... $ 633,757 $ 605,157 Cumulative preferred stock ............................. 95,328 95,328 Long-term debt ......................................... 646,835 646,845 ---------- ---------- 1,375,920 1,347,330 ---------- ---------- Current Liabilities Long-term debt due within one year ..................... -- 16,000 Accounts payable ....................................... 97,478 93,706 Trimble County Settlement (Note 14) .................... 17,511 28,300 Dividends declared ..................................... 20,131 19,672 Accrued taxes .......................................... 11,982 7,814 Accrued interest ....................................... 9,994 11,064 Other .................................................. 13,128 12,071 ---------- ---------- 170,224 188,627 ---------- ---------- Deferred Credits and Other Liabilities Accumulated deferred income taxes (Notes 1 and 8) ...... 241,681 204,816 Investment tax credit, in process of amortization ...... 80,040 84,037 Accumulated provision for pensions and related benefits 42,554 47,099 Customers' advances for construction ................... 10,033 9,251 Regulatory liability (Note 2) .......................... 77,287 88,242 Other .................................................. 8,973 10,088 ---------- ---------- 460,568 443,533 ---------- ---------- Commitments and Contingencies (Note 13) $2,006,712 $1,979,490 ========== ==========
The accompanying notes are an integral part of these financial statements. -26- LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Thousands of $)
December 31 ------------------------- 1996 1995 ----------- ----------- Common Equity Common stock, without par value - Authorized 75,000,000 shares, outstanding 21,294,223 shares .... $ 425,170 $ 425,170 Common stock expense ............................................ (836) (836) Unrealized gain (loss) on marketable securities, net of income taxes of $136 in 1996 and $153 in 1995 (Note 6) .............. 201 (226) Retained earnings ............................................... 209,222 181,049 ----------- ----------- 633,757 605,157 ----------- ----------- Cumulative Preferred Stock Redeemable on 30 days notice by the Company except, $5.875 series Shares Current Outstanding Redemption Price ----------- ---------------- $25 par value, 1,720,000 shares authorized - 5% series .......................................... 860,287 $ 28.00 21,507 21,507 Without par value, 6,750,000 shares authorized - Auction Rate ....................................... 500,000 100.00 50,000 50,000 $5.875 series ...................................... 250,000 Not redeemable 25,000 25,000 Preferred stock expense ......................................... (1,179) (1,179) ----------- ----------- 95,328 95,328 ----------- ----------- Long-Term Debt (Note 11) First mortgage bonds - Series due June 1, 1998, 6 3/4% ................................ 20,000 20,000 Series due July 1, 2002, 7 1/2% ................................ 20,000 20,000 Series due August 15, 2003, 6% ................................. 42,600 42,600 Pollution control series: K due December 1, 2016, 7 1/4% ............................... -- 27,500 L due December 1, 2016, 7 1/4% ............................... -- 22,500 N due February 1, 2019, 7 3/4% ............................... 35,000 35,000 O due February 1, 2019, 7 3/4% ............................... 35,000 35,000 P due June 15, 2015, 7.45% ................................... 25,000 25,000 Q due November 1, 2020, 7 5/8% ............................... 83,335 83,335 R due November 1, 2020, 6.55% ................................ 41,665 41,665 S due September 1, 2017, variable ............................ 31,000 31,000 T due September 1, 2017, variable ............................ 60,000 60,000 U due August 15, 2013, variable .............................. 35,200 35,200 V due August 15, 2019, 5 5/8% ................................ 102,000 102,000 W due October 15, 2020, 5.45% ................................ 26,000 26,000 X due April 15, 2023, 5.90% .................................. 40,000 40,000 ----------- ----------- Total first mortgage bonds ..................................... 596,800 646,800 Pollution control bonds (unsecured) - Jefferson County Series due September 1, 2026, variable ...... 22,500 -- Trimble County Series due September 1, 2026, variable ........ 27,500 -- ----------- ----------- Total unsecured long-term debt ................................. 50,000 -- ----------- ----------- Total long-term bonds .......................................... 646,800 646,800 Unamortized premium on bonds .................................... 35 45 ----------- ----------- 646,835 646,845 ----------- ----------- Total Capitalization .............................................. $ 1,375,920 $ 1,347,330 =========== ===========
The accompanying notes are an integral part of these financial statements. -27- 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. -28- 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. -29- 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. -30- 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. -31- The cost and estimated fair values of the Company's financial instruments as of December 31, 1996 and 1995 follow (in thousands of $):
1996 1995 ------------------- ------------------- Fair Fair Cost Value Cost Value ---- ----- ---- ----- Marketable securities ......................... $ 3,258 $ 3,595 $ 20,828 $ 20,449 Long-term investments - Not practicable to estimate fair value ...... 744 744 740 740 Preferred stock subject to mandatory redemption 25,000 24,938 25,000 25,000 Long-term debt ................................ 646,800 662,721 662,800 688,977 U.S. Treasury note and bond futures ........... -- 6 -- (105) Interest-rate swaps ........................... -- (319) -- (522)
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. -32- 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 $):
1996 1995 ----------------------------- ------------------------------ Fixed Fixed Equity Income Total Equity Income Total -------- -------- -------- -------- -------- -------- Cost ................................ $ 3,258 $ -- $ 3,258 $ 5,342 $ 15,486 $ 20,828 Unrealized gains .................... 572 -- 572 55 4 59 Unrealized losses ................... (235) -- (235) (193) (245) (438) -------- -------- -------- -------- -------- -------- Fair values ......................... $ 3,595 $ -- $ 3,595 $ 5,204 $ 15,245 $ 20,449 ======== ======== ======== ======== ======== ======== - ----------------------------------------------------------------------------------------------------- Fair Values: No maturity ....................... $ 2,126 $ -- $ 2,126 $ 4,565 $ -- $ 4,565 Contractual Maturities: Less than one year .............. 1,469 -- 1,469 639 2,710 3,349 One to five years ............... -- -- -- -- 8,808 8,808 Five to ten years ............... -- -- -- -- 831 831 Over ten years .................. -- -- -- -- 2,219 2,219 Not due at a single maturity date -- -- -- -- 677 677 -------- -------- -------- -------- -------- -------- Total Fair Values ................... $ 3,595 $ -- $ 3,595 $ 5,204 $ 15,245 $ 20,449 ======== ======== ======== ======== ======== ========
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. -33- 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. -34- 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. -35- 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% ====== ====== ====== -36- 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. -37- 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 -38- 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 -39- 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. -40- 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 -41- 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. -42- 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. -43- 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 --------------------------- -44- 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 ----- ---- --------- -------- 1996 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 1995 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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. -45- 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 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. -46- 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] -47- 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] -48- 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] -49- 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] -50- 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] -51- 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] -52- 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] -53- 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] -54- 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] -55- 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] -56- 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] -57- 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] -58- 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] -59- 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] -60- 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. -61- SCHEDULE II LOUISVILLE GAS AND ELECTRIC COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 1996 (Thousands of $)
Reserves Deducted from Assets in Balance Sheet ----------------------------- Other Accounts Property Receivable and (Uncollectible Investments Accounts) ----------- --------- Balance January 1, 1994 ...................................... $ 63 $1,474 Additions: Charged to costs and expenses ............................. 3,100 Deductions: Net charges of nature for which reserves were created ..... 3,371 ------ ------ Balance December 31, 1994 .................................... 63 1,203 Additions: Charged to costs and expenses ............................. 3,200 Deductions: Net charges of nature for which reserves were created ..... 3,043 ------ ------ Balance December 31, 1995 .................................... $ 63 $1,360 Additions: Charged to costs and expenses ............................. 2,600 Deductions: Net charges of nature for which reserves were created ..... 2,490 ------ ------ Balance December 31, 1996 .................................... $ 63 $1,470 ====== ======
-62- 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) -63- EX-10.39 2 EXHIBIT 10.39 EXHIBIT 10.39 MODIFICATION NO. 9 TO INTER-COMPANY POWER AGREEMENT DATED JULY 10, 1953 AMONG OHIO VALLEY ELECTRIC CORPORATION, APPALACHIAN POWER COMPANY (formerly APPALACHIAN ELECTRIC POWER COMPANY), THE CINCINNATI GAS & ELECTRIC COMPANY COLUMBUS SOUTHERN POWER COMPANY (formerly COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY), THE DAYTON POWER AND LIGHT COMPANY, INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY), KENTUCKY UTILITIES COMPANY, LOUISVILLE GAS AND ELECTRIC COMPANY, MONONGAHELA POWER COMPANY, OHIO EDISON COMPANY, OHIO POWER COMPANY (formerly THE OHIO POWER COMPANY), PENNSYLVANIA POWER COMPANY, THE POTOMAC EDISON COMPANY, SOUTHERN INDIANA GAS AND ELECTRIC COMPANY, THE TOLEDO EDISON COMPANY, and WEST PENN POWER COMPANY. ---------------------------- Dated as of August 17, 1995 ---------------------------- MODIFICATION NO. 9 TO INTER-COMPANY POWER AGREEMENT THIS AGREEMENT dated as of the 17th day of August, 1995, by and among OHIO VALLEY ELECTRIC CORPORATION (herein called "OVEC" or "Corporation"), APPALACHIAN POWER COMPANY (herein called "Appalachian"), THE CINCINNATI GAS & ELECTRIC COMPANY (herein called "Cincinnati"), COLUMBUS SOUTHERN POWER COMPANY (formerly COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY) (herein called "Columbus"), THE DAYTON POWER AND LIGHT COMPANY (herein called "Dayton"), INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY) (herein called "Indiana"), KENTUCKY UTILITIES COMPANY (herein called "Kentucky"), LOUISVILLE GAS AND ELECTRIC COMPANY (herein called "Louisville"), MONONGAHELA POWER COMPANY (herein called "Monongahela"), OHIO EDISON COMPANY (herein called "Ohio Edison"), OHIO POWER COMPANY (herein called "Ohio Power"), PENNSYLVANIA POWER COMPANY (herein called "Pennsylvania"), THE POTOMAC EDISON COMPANY (herein called "Potomac"), SOUTHERN INDIANA GAS AND ELECTRIC COMPANY (herein called "Southern Indiana"), THE TOLEDO EDISON COMPANY (herein called "Toledo"), and WEST PENN POWER COMPANY (herein called "West Penn"), all of the foregoing, other than OVEC, being herein sometimes collectively referred to as the Sponsoring Companies and individually as a Sponsoring Company. 1 W I T N E S S E T H T H A T WHEREAS, Corporation and the United States of America have heretofore entered into Contract No. AT-(40-1)-1530 (redesignated Contract No. E-(40-1)-1530, later redesignated Contract No. EY-76-C-05-1530 and later redesignated Contract No. DE-AC05-76OR01530), dated October 15, 1952, providing for the supply by Corporation of electric utility services to the United States Atomic Energy Commission (hereinafter called "AEC") at AEC's project near Portsmouth, Ohio (hereinafter called the "Project"), which Contract has heretofore been modified by Modification No. 1, dated July 23, 1953, Modification No. 2, dated as of March 15, 1964, Modification No. 3, dated as of May 12, 1966, Modification No. 4, dated as of January 7, 1967, Modification No. 5, dated as of August 15, 1967, Modification No. 6, dated as of November 15, 1967, Modification No. 7, dated as of November 5, 1975, Modification No. 8, dated as of June 23, 1977, Modification No. 9, dated as of July 1, 1978, Modification No. 10, dated as of August 1, 1979, Modification No. 11, dated as of September 1, 1979, Modification No. 12, dated as of August 1, 1981, Modification No. 13, dated as of September 1, 1989, Modification No. 14, dated as of January 15, 1992, and Modification No. 15, dated as of February 1, 1993 (said Contract, as so modified, is hereinafter called the "DOE Power Agreement"); and WHEREAS, pursuant to the Energy Reorganization Act of 1974, the AEC was abolished on January 19, 1975 and certain of its 2 functions, including the procurement of electric utility services for the Project, were transferred to and vested in the Administrator of Energy Research and Development; and WHEREAS, pursuant to the Department of Energy Organization Act, on October 1, 1977, all of the functions vested by law in the Administrator of Energy Research and Development or the Energy Research and Development or the Energy Research and Development Administration were transferred to, and vested in, the Secretary of Energy, the statutory head of the Department of Energy (hereinafter called "DOE"); and WHEREAS, the parties hereto have entered into a contract, herein called the "Inter-Company Power Agreement," dated July 10, 1953, governing, among other things, (a) the supply by the Sponsoring Companies of Supplemental Power in order to enable Corporation to fulfill its obligations under the DOE Power Agreement, and (b) the rights of the Sponsoring Companies to receive Surplus Power (as defined in the Agreement identified in the next clause in this preamble) as may be available at the Project Generating Stations and the obligations of the Sponsoring Companies to pay therefor; and WHEREAS, the Inter-Company Power Agreement has heretofore been amended by Modification No. 1, dated as of June 3, 1966, Modification No. 2 dated as of January 7, 1967, Modification No. 3, dated as of November 15, 1967, Modification No. 4, dated as of November 5, 1975, Modification No. 5, dated as of September 1, 3 1979, Modification No. 6, dated as of August 1, 1981, Modification No. 7, dated as of January 15, 1992, and Modification No. 8, dated as of January 19, 1994 (said contract so amended and as modified and amended by this Modification No. 9 being herein and therein sometimes called the "Agreement"); and WHEREAS, OVEC and the Sponsoring Companies desire to enter into this Modification No. 9 as more particularly hereinafter provided; NOW, THEREFORE, the parties hereto agree with each other as follows: 1. Delete SUBSECTION 6.023 and substitute therefor the following: 6.023 Determine the total energy charge to be billed as DOE Emergency Energy (as defined in SUBSECTION 6.037) for such month, such charge to be an amount equal to the product of the total net charges for such month at the project generating stations to Account 703 (Fuel) of the Uniform System of Accounts, and the ratio of (a) the billing kWh of DOE Emergency Energy for such month plus the transmission losses thereon from the 345 kV busses of the project generating stations to the point of delivery to (b) the total net kWh generated at the project generating stations during such month corrected for losses to the 345 kV busses thereof. Such losses shall be determined by such methods and procedures as may be mutually agreed upon. 2. Insert after SUBSECTION 6.023 a new SUBSECTION 6.024 as follows: 6.024 Determine for such month the difference between the total cost of fuel as described in subsection 6.021 above and the sum of (a) the total energy charge to be billed DOE as described in subsection 6.022 above and (b) the energy 4 charge to be billed as DOE Emergency Energy as described in subsection 6.023 above. For the purposes hereof the difference so determined shall be the fuel cost allocable for such month to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy. Each Sponsoring Company shall pay Corporation, for such month, an amount equal to (a) an amount obtained by multiplying the billing kilowatt-hours of Surplus Energy availed of by such Sponsoring Company during such month by the average station heat rate of the Project Generating Stations times the average cost per Btu (determined in a uniform manner for all Sponsoring Companies in conformity with any applicable requirements of Account 703 (Fuel) of the Uniform System of Accounts) of all fuel consumed by said Sponsoring Company in its own generating stations, both averages to be computed in respect of the month next preceding that for which payment is being made, plus (b) its Power Participation Ratio of the excess, if any, for such month of the fuel costs of the Corporation allocable to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy over the aggregate of the amounts computed with respect to all Sponsoring Companies under (a) above, minus (c) its Power Participation Ratio of the excess, if any, for such month of the aggregate of the amounts computed with respect to all Sponsoring Companies under (a) above over the fuel costs of the Corporation allocable to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy. 3. Insert after SUBSECTION 6.036 a new SUBSECTION 6.037 as follows: 6.037 DOE EMERGENCY POWER In the event that the power and energy available to DOE's uranium enrichment facility near Paducah, Kentucky is insufficient to prevent or alleviate an emergency at such facility, at the request of DOE, and provided the Sponsoring Companies agree to release their rights to receive from Corporation power and energy to which they would otherwise have been entitled, Corporation may in its sole discretion agree to make available such power and energy for DOE's Paducah Facility (such power being herein called "DOE Emergency Power" and the energy associated therewith being called "DOE Emergency Energy"). 5 The aggregate of the kWh of DOE Emergency Energy scheduled for all the hours of a month shall be the "Scheduled kWh of DOE Emergency Energy" for such month. To the Scheduled kWh of DOE Emergency Energy so computed for such month shall be added the number of kWh of transmission losses applicable thereto computed by such methods and procedures as may be mutually agreed upon, and the sum so computed is herein called the "Billing kWh of DOE Emergency Energy." Corporation will pay to each Sponsoring Company for DOE Emergency Power during any month an amount equal to an emergency power surcharge ("DOE Emergency Power Surcharge") which shall be determined based on each Sponsoring Company's hourly net costs per kilowatt of reducing load or purchasing power from alternative sources, which costs are attributable to the provision of DOE Emergency Power and/or DOE Emergency Energy. Corporation and Sponsoring Companies acknowledge that they may not know until after the fact the amount of any DOE Emergency Power Surcharge and that any estimates thereof provided by Sponsoring Companies are not binding. In order that DOE Emergency Power and DOE Emergency Energy may be delivered to DOE's uranium enrichment facility in Paducah, Kentucky, such power and energy may be sold to intervening entities which may resell such power and energy for ultimate delivery to DOE. 4. This Modification No. 9 shall become effective at 12:00 o'clock Midnight on the day on which Corporation shall advise the other parties to this Modification No. 9 (to be later confirmed in writing) that all conditions precedent to the effectiveness of this Modification No. 9 shall have been satisfied. 5. The Inter-Company Power Agreement, as modified by Modifications Nos. 1, 2, 3, 4, 5, 6, 7 and 8 and as hereinbefore provided, is hereby in all respects confirmed. 6. The Modification No. 9 may be executed in any number of copies and by the different parties hereto on separate 6 counterparts, each of which shall be deemed an original but all of which together shall constitute a single agreement. IN WITNESS WHEREOF, the parties hereto have executed this Modification No. 9 as of the day and year first written above. OHIO VALLEY ELECTRIC CORPORATION BY: _____________________________________ APPALACHIAN POWER COMPANY BY: _____________________________________ THE CINCINNATI GAS & ELECTRIC COMPANY BY: _____________________________________ COLUMBUS SOUTHERN POWER COMPANY BY: _____________________________________ THE DAYTON POWER AND LIGHT COMPANY BY: _____________________________________ INDIANA MICHIGAN POWER COMPANY BY: _____________________________________ 7 KENTUCKY UTILITIES COMPANY BY: _____________________________________ LOUISVILLE GAS AND ELECTRIC COMPANY BY: _____________________________________ MONONGAHELA POWER COMPANY BY: _____________________________________ OHIO EDISON COMPANY BY: _____________________________________ OHIO POWER COMPANY BY: _____________________________________ PENNSYLVANIA POWER COMPANY BY: _____________________________________ THE POTOMAC EDISON COMPANY BY: _____________________________________ SOUTHERN INDIANA GAS AND ELECTRIC COMPANY BY: _____________________________________ 8 THE TOLEDO EDISON COMPANY BY: _____________________________________ WEST PENN POWER COMPANY BY: _____________________________________ 9 EX-10.41 3 EXHIBIT 10.41 EXHIBIT 10.41 GAS TRANSPORTATION AGREEMENT BETWEEN TEXAS GAS TRANSMISSION CORPORATION AND LOUISVILLE GAS AND ELECTRIC COMPANY (TERM THROUGH: OCTOBER 31, 2000) DATED MARCH 1, 1995 INDEX PAGE NO. -------- ARTICLE I Definitions 1 ARTICLE II Transportation Service 1 ARTICLE III Scheduling 2 ARTICLE IV Points of Receipt and Delivery 3 ARTICLE V Term of Agreement 3 ARTICLE VI Point(s) of Measurement 3 ARTICLE VII Facilities 4 ARTICLE VIII Rates and Charges 4 ARTICLE IX Miscellaneous 5 EXHIBIT "A" FIRM POINT(S) OF RECEIPT EXHIBIT "A-1" SECONDARY POINT(S) OF RECEIPT EXHIBIT "B" FIRM POINT(S) OF DELIVERY EXHIBIT "C" SUPPLY LATERAL CAPACITY STANDARD FACILITIES KEY 1 FIRM TRANSPORTATION AGREEMENT THIS AGREEMENT, made and entered into this 1st day of March, 1995, by and between Texas Gas Transmission Corporation, a Delaware corporation, hereinafter referred to as "Texas Gas," and Louisville Gas and Electric Company, a Kentucky corporation, hereinafter referred to as "Customer." WITNESSETH: WHEREAS, Customer has natural gas which cannot be moved into its system/which it desires Texas Gas to move through its existing facilities; and WHEREAS, Texas Gas has the ability in its pipeline system to move natural gas for the account of Customer; and WHEREAS, Customer desires that Texas Gas transport such natural gas for the account of Customer; and WHEREAS, Customer and Texas Gas are of the opinion that the transaction referred to above falls within the provisions of Section 284.223 of Subpart G of Part 284 of the Federal Energy Regulatory Commission's (Commission) regulations and the blanket certificate issued to Texas Gas in Docket No. CP88-686-000, and can be accomplished without the prior approval of the Commission; NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto covenant and agree as follows: ARTICLE I DEFINITIONS 1.1 Definition of Terms of the General Terms and Conditions of Texas Gas's FERC Gas Tariff on file with the Commission is hereby incorporated by reference and made a part of this Agreement. ARTICLE II TRANSPORTATION SERVICE 2.1 Subject to the terms and provisions of this Agreement, Customer agrees to deliver or cause to be delivered to Texas Gas, at the Point(s) of Receipt in Exhibit "A" hereunder, Gas for Transportation, and Texas Gas agrees to receive, transport, and redeliver, at the Point(s) of Delivery in Exhibit "B" hereunder, Equivalent Quantities of Gas to Customer or for the account of Customer, in accordance with Section 3 of Texas Gas's effective FT Rate Schedule and the 2 terms and conditions contained herein, up to 0 MMBtu per day during the winter season, and up to 8,000 MMBtu per day during the summer season, which shall be Customer's Firm Transportation Contract Demand, and up to 0 MMBtu during the winter season, and up to 1,712,000 MMBtu during the summer season, which shall be Customer's Seasonal Quantity Levels. 2.2 Customer shall reimburse Texas Gas for the Quantity of Gas required for fuel, company use, and unaccounted for associated with the transportation service hereunder in accordance with Section 16 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. The applicable fuel retention percentage(s) is shown on Exhibit "A". Texas Gas may adjust the fuel retention percentage as operating circumstances warrant; however, such change shall not be retroactive. Texas Gas agrees to give Customer thirty (30) days written notice before changing such percentage. 2.3 Texas Gas, at its sole option, may, if tendered by Customer, transport daily quantities in excess of the Transportation Contract Demand. 2.4 In order to protect its system, the delivery of gas to its customers and/or the safety of its operations, Texas Gas shall have the right to vent excess natural gas delivered to Texas Gas by Customer or Customer's supplier(s) in that part of its system utilized to transport gas received hereunder. Prior to venting excess gas, Texas Gas will use its best efforts to contact Customer or Customer's supplier(s) in an attempt to correct such excess deliveries to Texas Gas. Texas Gas may vent such excess gas solely within its reasonable judgment and discretion without liability to Customer, and a pro rata share of any gas so vented shall be allocated to Customer. Customer's pro rata share shall be determined by a fraction, the numerator of which shall be the quantity of gas delivered to Texas Gas at the Point of Receipt by Customer or Customer's supplier(s) in excess of Customer's confirmed nomination and the denominator of which shall be the total quantity of gas in excess of total confirmed nominations flowing in that part of Texas Gas's system utilized to transport gas, multiplied by the total quantity of gas vented or lost hereunder. 2.5 Any gas imbalance between receipts and deliveries of gas, less fuel and PVR adjustments, if applicable, shall be cleared each month in accordance with Section 17 of the General Terms and Conditions in Texas Gas's FERC Gas Tariff. Any imbalance remaining at the termination of this Agreement shall also be cashed-out as provided herein. ARTICLE III SCHEDULING 3.1 Customer shall be obligated five (5) working days prior to the end of each month to furnish Texas Gas with a schedule of the estimated daily quantity(ies) of gas it desires to be received, transported, and redelivered for the following month. Such schedules will show the quantity(ies) of gas Texas Gas will receive from Customer at the Point(s) of Receipt, along with the identity of the supplier(s) that is delivering or causing to be delivered to Texas Gas quantities for Customer's account at each point of Receipt for which a nomination has been made. 3 3.2 Customer shall give Texas Gas, after the first of the month, at least twenty-four (24) hours notice prior to the commencement of any day in which Customer desires to change the quantity(ies) of gas it has scheduled to be delivered to Texas Gas at the Point(s) of Receipt. Texas Gas agrees to waive this 24-hour prior notice and implement nomination changes requested by Customer to commence in such lesser time frame subject to Texas Gas's being able to confirm and verify such nomination change at both Receipt and Delivery Points, and receive PDAs reflecting this nomination change at both Receipt and Delivery Points. Texas Gas will use its best efforts to make the nomination change effective at the time requested by Customer; however, if Texas Gas is unable to do so, the nomination change will be implemented as soon as confirmation is received. ARTICLE IV POINTS OF RECEIPT, DELIVERY, AND SUPPLY LATERAL ALLOCATION 4.1 Customer shall deliver or cause to be delivered natural gas to Texas Gas at the Point(s) of Receipt specified in Exhibit "A" attached hereto and Texas Gas shall redeliver gas to Customer or for the account of Customer at the Point(s) of Delivery specified in Exhibit "B" attached hereto in accordance with Sections 7 and 15 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. 4.2 Customer's preferential capacity rights on each of Texas Gas's supply laterals shall be as set forth in Exhibit "C" attached hereto, in accordance with Section 34 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE V TERM OF AGREEMENT 5.1 This Agreement shall become effective upon its execution and remain in full force and effect with a primary term beginning April 1, 1995, (with the rates and charges described in Article VIII becoming effective on that date) and extending through October 31, 1995. At the end of such primary term, or any subsequent roll-over term of five (5) years, this Agreement shall automatically be extended for an additional roll-over term of five (5) years, unless Customer terminates this Agreement at the end of such primary or roll-over term by giving Texas Gas at least 365 days advance written notice prior to the expiration of the primary term or any subsequent roll-over term. ARTICLE VI POINT(S) OF MEASUREMENT 6.1 The gas shall be delivered by Customer to Texas Gas and redelivered by Texas Gas to Customer at the Point(s) of Receipt and Delivery hereunder. 4 6.2 The gas shall be measured or caused to be measured by Customer and/or Texas Gas at the Point(s) of Measurement which shall be as specified in Exhibits "A", "A-I", and "B" herein. In the event of a line loss or leak between the Point of Measurement and the Point of Receipt, the loss shall be determined in accordance with the methods described contained in Section 3, "Measuring and Measuring Equipment," contained in the General Terms and Conditions of First Revised Volume No. 1 of Texas Gas's FERC Gas Tariff. ARTICLE VII FACILITIES 7.1 Texas Gas and Customer agree that any facilities required at the Point(s) of Receipt, Point(s) of Delivery, and Point(s) of Measurement shall be installed, owned, and operated as specified in Exhibits "A", "A-I", and "B" herein. Customer may be required to pay or cause Texas Gas to be paid for the installed cost of any new facilities required as contained in Sections 1.3, 1.4, and 1.5 of Texas Gas's FT Rate Schedule. Customer shall only be responsible for the installed cost of any new facilities described in this Section if agreed to in writing between Texas Gas and Customer. ARTICLE VIII RATES AND CHARGES 8.1 Each month, Customer shall pay Texas Gas for the service hereunder an amount determined in accordance with Section 5 of Texas Gas's FT Rate Schedule contained in Texas Gas's FERC Gas Tariff, which Rate Schedule is by reference made a part of this Agreement. The maximum rates for such service consist of a monthly reservation charge multiplied by Customer's firm transportation demand as specified in Section 2.1 herein. The reservation charge shall be billed as of the effective date of this Agreement. In addition to the monthly reservation charge, Customer agrees to pay Texas Gas each month the maximum commodity charge up to Customer's Transportation Contract Demand. For any quantities delivered by Texas Gas in excess of Customer's Transportation Contract Demand, Customer agrees to pay the maximum FT overrun commodity charge. In addition, Customer agrees to pay: (a) Texas Gas's Fuel Retention percentage(s). (b) The currently effective GRI funding unit, if applicable, the currently effective FERC Annual Charge Adjustment unit charge (ACA), the currently effective Take-or-Pay surcharge, or any other then currently effective surcharges, including but not limited to Order 636 Transition Costs. If Texas Gas declares force majeure which renders it unable to perform service herein, then Customer shall be relieved of its obligation to pay demand charges for that part of its FT Contract Demand affected by such force majeure event until the force majeure event is remedied. 5 Unless otherwise agreed to in writing by Texas Gas and Customer, Texas Gas may, from time to time, and at any time selectively after negotiation, adjust the rate(s) applicable to any individual Customer; provided, however, that such adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor shall they be less than the Minimum Rate(s) set forth in the currently effective Sheet No. 10 of this Tariff. If Texas Gas so adjusts any rates to any Customer, Texas Gas shall file with the Commission any and all required reports respecting such adjusted rate. 8.2 In the event Customer utilizes a Secondary Point(s) of Receipt or Delivery for transportation service herein, Customer will continue to pay the monthly reservation charges as described in Section 8.1 above. In addition, Customer will pay the maximum commodity charge applicable to the zone in which gas is received and redelivered up to Customer's Transportation Contract Demand and the maximum overrun commodity charge for any quantities delivered by Texas Gas in excess of Customer's winter season or summer season Transportation Contract Demand. Customer also agrees to pay the ACA, Take-or-Pay Surcharge, GRI charges, fuel retention charge, and any other effective surcharges, if applicable, as described in Section 8.1 above. 8.3 It is further agreed that Texas Gas may seek authorization from the Commission and/or other appropriate body for such changes to any rate(s) and terms set forth herein or in Rate Schedule FT, as may be found necessary to assure Texas Gas just and reasonable rates. Nothing herein contained shall be construed to deny Customer any rights it may have under the Natural Gas Act, as amended, including the right to participate fully in rate proceedings by intervention or otherwise to contest increased rates in whole or in part. 8.4 Customer agrees to fully reimburse Texas Gas for all filing fees, if any, associated with the service contemplated herein which Texas Gas is required to pay to the Commission or any agency having or assuming jurisdiction of the transactions contemplated herein. 8.5 Customer agrees to execute or cause its supplier or processor to execute a separate agreement with Texas Gas providing for the transportation of any liquids and/or liquefiables, and agrees to pay or reimburse Texas Gas, or cause Texas Gas to be paid or reimbursed, for any applicable rates or charges associated with the transportation of such liquids and/or liquefiables, as specified in Section 24 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE IX MISCELLANEOUS 9.1 Texas Gas's Transportation Service hereunder shall be subject to receipt of all requisite regulatory authorizations from the Commission, or any successor regulatory authority, and any other necessary governmental authorizations, in a manner and form acceptable to Texas Gas. The parties agree to furnish each other with any and all information necessary to comply with any laws, orders, rules, or regulations. 6 9.2 Except as may be otherwise provided, any notice, request, demand, statement, or bill provided for in this Agreement or any notice which a party may desire to give the other shall be in writing and mailed by regular mail, or by postpaid registered mail, effective as of the postmark date, to the post office address of the party intended to receive the same, as the case may be, or by facsimile transmission, as follows: Texas Gas Texas Gas Transmission Corporation 3800 Frederica Street Post Office Box 1160 Owensboro, Kentucky 42302 Attention: Gas Revenue Accounting (Billings and Statements) Customer Services (Other Matters) Gas Transportation and Capacity Allocation (Nominations) Fax (502) 926-8686 Customer Louisville Gas and Electric Company 820 West Broadway Louisville, Kentucky 40202 Attention: Mr. J. Clay Murphy The address of either party may, from time to time, be changed by a party mailing, by certified or registered mail, appropriate notice thereof to the other party. Furthermore, if applicable, certain notices shall be considered duly delivered when posted to Texas Gas's Electronic Bulletin Board, as specified in Texas Gas's tariff. 9.3 This Agreement shall be governed by the laws of the State of the Kentucky. 9.4 Each party agrees to file timely all statements, notices, and petitions required under the Commission's Regulations or any other applicable rules or regulations of any governmental authority having jurisdiction hereunder and to exercise due diligence to obtain all necessary governmental approvals required for the implementation of this Transportation Agreement. 9.5 All terms and conditions of Rate Schedule FT and the attached Exhibits "A", "A-I", "B", and "C" are hereby incorporated to and made a part of this Agreement. 9.6 This contract shall be binding upon and inure to the benefit of the successors, assigns, and legal representatives of the parties hereto. 7 9.7 Neither party hereto shall assign this Agreement or any of its rights or obligations hereunder without the consent in writing of the other party. Notwithstanding the foregoing, either party may assign its right, title and interest in, to and by virtue of this Agreement including any and all extensions, renewals, amendments, and supplements thereto, to a trustee or trustees, individual or corporate, as security for bonds or other obligations or securities, without such trustee or trustees assuming or becoming in any respect obligated to perform any of the obligations of the assignor and, if any such trustee be a corporation, without its being required by the parties hereto to qualify to do business in the state in which the performance of this Agreement may occur, nothing contained herein shall require consent to transfer this Agreement by virtue of merger or consolidation of a party hereto or a sale of all or substantially all of the assets of a party hereto, or any other corporate reorganization of a party hereto. 9.8 This Agreement insofar as it is affected thereby, is subject to all valid rules, regulations, and orders of all governmental authorities having jurisdiction. 9.9 No waiver by either party of any one or more defaults by the other in the performance of any provisions hereunder shall operate or be construed as a waiver of any future default or defaults whether of a like or a different character. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective representatives thereunto duly authorized, on the day and year first above written. ATTEST: TEXAS GAS TRANSMISSION CORPORATION _____________________________ By: ____________________________ Secretary Vice President WITNESSES: LOUISVILLE GAS AND ELECTRIC COMPANY _____________________________ By: ____________________________ Vice President _____________________________ Attest: ________________________ Secretary Date of Execution by Customer: _____________________________ 8 Contract No. T6487 Summer Season - Exhibit "A" Firm Point(s) of Receipt Louisville Gas and Electric Company Firm Transportation Agreement Daily Firm Meter Capacity Lateral Segment Zone No. Name MBtu - -------------------------------------------------------------------------------- South Leg Offshore in at Egan SL 2770 Vermilion 267F 2,116 SL 2782 Vermilion 267C 1,254 SL 2774 Vermilion 256D 951 SL 9342 Vermilion 255/256E 225 SL 2776 S.S. 248D 4,811 SL 2781 S.S. 247F 3,592 HIOS (at ANR-Eunice) H.I. 573 SL 2859 H I A-573B COMPLEX 12,303 This exhibit reflects the combined total receipt point capacity held by Louisville Gas and Electric Company under the 2-year, 5-year and 8-year agreements for Contract No. T6487. Amendments in contract quantities in either the 2-year, 5-year or 8-year agreements will result in an amendment of this exhibit. 9 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT SUPPLY Meter Lateral Segment Zone No. Supply Point - -------------------------------------------------------------------------------- NORTH LOUISIANA Carthage-Haughton 1 2102 Champlin 1 9805 Delhi 1 9051 Grigsby 1 9860 Nelson-Greenwood/Waskom 1 8116 Texas Eastern-Sligo 1 9884 Valero-Carthage Haughton-Sharon 1 8003 Barksdale 1 2455 Beacon 1 9866 Cornerstone-Ada 1 2173 Crystal Oil-West Arcadia 1 2340 F.E. Hargraves-Minden 1 2186 LGI #1 1 2456 McCormick 1 2457 Minden-Hunt 1 2459 Minden Pan-Am #1 1 9819 Nelson-Sibley 1 9461 Olin-McGoldrick 1 2760 Sligo Plant 1 9834 Texaco-Athens Sharon 1 2010 Fina Oil-HICO 1 9818 PGC-Bodcaw 1 2757 Texas Eastern-Sharon Sharon-East 1 2631 Calhoun Plant 1 2632 Dubach 1 2202 Ergon-Monroe 1 8760 Lonewa 1 8020 MRT-Bastrop 1 9302 Munce 1 9812 Par Minerals/Downsville 1 9823 Reliance-Bernice 1 2612 Reliance-West Monroe 1 2634 Southwest-Guthrie 10 EAST Bosco-Eunice SL 2015 Amerada Hess SL 2016 Amerada Hess-South Lewisburg SL 2385 D.B. McClinton #1 SL 9844 Germany Oil-Church Point SL 2288 Great Southern-Mowata #2 SL 9804 Great Southern-Mowata #3 SL 2289 Great Southern-South Lewisburg SL 8142 Ritchie SL 9119 Sevarg SL 2740 Superior-Pure SOUTHEAST Blk. 8-Morgan City SL 2198 Bois D'Arc SL 9142 Bois D'Arc-Pelican Lake SL 2109 Chevron-Block 8 SL 2638 Coon Point SL 2845 Lake Pagie SL 9817 Mustang-Bayou Piquant SL 2460 Peltex Deep Saline #1 SL 2480 S.S. 41 SL 9471 Sohio SL 9888 Star Oil & Gas-Bay Junop SL 9187 Stone-South Timbalier SL 2755 Texaco-Bay Junop SL 9836 Texaco-Dog Lake SL 2463 Toce Oil SL 2850 Union Oil-N. Lake Pagie SL 9883 Zeit-Lake Pagie Henry-Lafayette SL 8190 Faustina-Henry SL 2790 Henry Hub Lafayette-Eunice SL 2153 Branch-Cox SL 2125 California Co.-North Duson SL 2137 California Co.-South Bosco #1 SL 2138 California Co.-South Bosco #2 SL 2600 Cayman-Anslem Coulee SL 9852 CNG-South Rayne SL 2389 Duson SL 9837 Excel-Judice SL 8068 Exch. O&G-No. Maurice SL 2601 Fina Oil-Anslem Coulee SL 8040 Florida 11 SL 2290 Gulf Transport-Church Pt. SL 2148 Maurice Cox SL 9906 Quintana-South Bosco SL 9005 Rayne-Columbia Gulf SL 2045 Riceland-North Tepetate SL 8067 South Scott SL 2810 Tidewater-North Duson SL 8051 Youngsville Maurice-Freshwater SL 9822 Cities Service-Nunez SL 2147 CNG-Hell Hole Bayou SL 2203 Deck Oil-Perry/Hope SL 9808 Duhon/Parcperdue SL 9044 EDC-N. Parcperdue SL 9160 LLOG-Abbeville SL 2394 LRC-Theall SL 9800 May Petroleum SL 2424 McCain-Maurice SL 2748 Parc Perdue SL 2749 Par Perdue 2 SL 9830 R&R Res-Abbeville SL 2706 Sun Ray SL 9422 UNOCAL-Freshwater Bayou SL 2840 UNOCAL-N. Freshwater Bayou Morgan City-Lafayette SL 2064 Amoco-Charenton SL 9173 ANR-Calumet (Rec.) SL 9803 Atlantic SL 9809 B.H. Petroleum-S.E. Avery SL 2080 Bayou Sale-British Am SL 9881 Bridgeline-Berwick SL 2085 British American-Ramos SL 9425 Charenton SL 9047 Florida Gas-E.B. Pigeon SL 2454 FMP/Bayou Postillion SL 8059 Franklin SL 2208 Frantzen SL 9898 Hadson-East Bayou Pigeon SL 2188 Lamson SL 9854 Linder Oil-Bayou Penchant SL 9853 Linder Oil-Garden City SL 2189 Rutledge Deas SL 2636 Shell-Bayou Pigeon SL 9902 Smith Production-Charenton SL 2035 Southwest-Jeanerette 12 SL 9895 Texaco-Bayou Sale SL 8205 Transco-Myette Point SL 9829 Trunkline-Centerville SL 9350 Vulcan SL 9835 W.T. Burton-Lake Palourde Offshore Points enter at Calumet SL 2583 E.I. 273A SL 2158 E.I. 273A/273A/284B SL 2584 E.I. 273B SL 2834 E.I. 276C SL 2771 E.I. 287D SL 2151 E.I. 292B SL 9339 E.I. 292B/286I SL 9419 E.I. 292B/286I/293 SL 2550 E.I. 293/308/315 SL 2773 E.I. 307E SL 2154 E.I. 309C SL 2155 E.I. 309G SL 2157 E.I. 309H SL 9886 E.I. 309H/309H/309J SL 2156 E.I. 314F/309C/314F SL 2780 SMI 11C SL 2425 SMI 161 SL 2783 S.S. 204/219 Thibodaux-Morgan City SL 2250 A.Glassell-Chacahoula SL 2047 Alliance Exploration SL 9029 Coastal-Chacahoula SL 2835 Lake Palourde SL 9873 Linder Oil-Chacahoula SL 9175 LLOG-Chacahoula SL 9847 LRC-Choctaw SL 2440 Magna-Chacahoula #1 SL 2445 Magna-St. John #2 SL 2470 Patterson-Chacahoula SL 2135 Simon Pass SOUTH Egan-Eunice SL 9851 Booher-Iota SL 9003 Egan Offshore Points entering at Egan SL 9310 E.I. 278/S.S. 247F SL 9131 E.I. 278/S.S. 248D SL 9128 E.I. 299/S.S. 271A 13 SL 9129 E.I. 299/S.S. 271A/S.S. 271B SL 9423 E.I. 320/324 SL 9122 E.I. 320/325A SL 9123 E.I. 342/366A SL 2793 E.I. 342/372A SL 9399 E.I. 342/384A SL 2767 E.I. 342C SL 2786 E.I. 343B SL 9363 E.I. 349/349A SL 9364 E.I. 349/349A/349B SL 2788 E.I. 365 SL 9369 E.I. 365A/365A/348 SL 9120 E.I. 372A SL 2781 S.S. 247F SL 2776 S.S. 248D SL 9429 S.S. 248D/248G SL 2778 S.S. 271A SL 2785 S.S. 271B/271A/271B SL 9427 Vermilion 248/255A/255H SL 9342 Vermilion 255/256E SL 9424 Vermilion 255/256E/268G SL 2774 Vermilion 256D SL 9105 Vermilion 267/275A SL 9340 Vermilion 267/287A SL 9341 Vermilion 267/287A/276 SL 9159 Vermilion 267/287A/277 SL 9374 Vermilion 267/289A SL 2782 Vermilion 267C SL 2770 Vermilion 267F SOUTHWEST East Cameron-Lowry SL 9872 E.C. 9A SL 2581 E.C. 14 SL 2860 Lake Arthur SL 2033 Little Cheniere-Arco SL 2034 Little Cheniere-Linder SL 2392 LRC-Grand Cheniere Lowry-Eunice SL 9843 Mobil-Lowry SL 9446 NGPL-Lowry SL 2437 ENOGEX/NGPL Tap Washita SL 9169 TEX SW/NGPL Washita SL 9171 Transok/NGPL Inter #2 Beckham SL 9170 Transok/NGPL Inter #2 Custer SL 9172 Transok/NGPL Waggs Wheeler 14 WEST Iowa-Eunice SL 2091 Caribbean-China #1 SL 2092 Caribbean-China #2 SL 2093 Caribbean-China #3 SL 9038 Coastal/ANR-Iowa SL 9839 Great Southern-Woodlawn SL 8170 Iowa SL 9445 Kilroy Riseden-Woodlawn SL 9186 Linder Oil-Woodlawn SL 9890 Source Petroleum-S. Elton #1 SL 9896 Source Petroleum-S. Elton #2 SL 2883 Tee Oil-Woodlawn Mallard Bay-Woodlawn SL 2140 California Co.-South Thornwell SL 2615 Caroline Hunt Sands-S. Thornwell SL 2170 Cockrell-North Chalkley SL 9828 Denovo-Lake Arthur SL 2207 Franks Petroleum-Chalkley SL 9028 Gas Energy Development-Hayes SL 2355 Humble-Chalkley SL 2383 IMC Wintershall-Chalkley SL 9848 Lamson Onshore-Mallard Bay SL 8071 LRC-Mallard Bay SL 2701 Samedan-N. Chalkley SL 2635 Shell-Chalkley SL 2266 South Mallard Bay-Americal SL 2822 Superior-S. Thornwell SL 9879 Total Minatome-Bell City SL 2885 Union Texas-Welsh SL 2853 Welsh Field W.C. 294 Entering at ANR-Eunice SL 9026 W.C. 167/132 SL 9135 W.C. 167/HIOS Mainline SL 9136 W.C. 167/Near Shore SL 9396 W.C. 293/H.I. 120/H.I. 120-128 SL 9383 W.C. 293/H.I. 167/H.I. 167-166 SL 2838 W.C. 294 HIOS Offshore Points entering at ANR-Eunice H.I. 247 SL 2868 H.I. A-247/A-244A/A-231 SL 9176 H.I. A-247/A-245 15 H.I. 283 SL 9894 H.I. A-283/A-283A SL 2855 H.I. A-285/A-282 H.I. 303 SL 2858 H.I. A-302A/A-303 H.I. A-345 SL 2863 H.I. A-334A/A-335 SL 9327 H.I. A-345/A-325A H.I. A-498 SL 2867 H.I. A-462 SL 9375 H.I. A-477/A-462/A-486 SL 2534 H.I. A-498/A-489 SL 2533 H.I. A-498/A-489/A-474 SL 2535 H.I. A-498/A-489/A-499 SL 9371 H.I. A-498/A-490 SL 2856 H.I. A-498/A-517 H.I. A-539 SL 2537 H.I. A-539/A-480 SL 9365 H.I. A-539/A-511 SL 9376 H.I. A-539/A-532 SL 9328 H.I. A-539/A-550 SL 9901 H.I. A-539/A-552/A-551 SL 9889 H.I. A-539/A-552/A-553 SL 2539 H.I. A-539/A-567 SL 9380 H.I. A-539/A-568 H.I. A-555 SL 2857 H.I. A-531A SL 2861 H.I. A-536C SL 2862 H.I. A-537B SL 9127 H.I. A-537B/A-537D/A-556 SL 9308 H.I. A-555 SL 9125 H.I. A-555/A-537D/A-556 SL 9887 H.I. A-555/A-557A/A-556 H.I. A-573 SL 9909 H.I. A-573/A-384/G B 224 SL 2859 H.I. A-573B Complex 16 SL 2542 H.I. A-595CF Complex H.I. A-582 SL 9165 H.I. A-582/A-561A SL 9133 H.I. A-582/E.B. 110 SL 9377 H.I. A-582/E.B. 160/Various SL 9134 H.I. A-582/E.B. 165 MAINLINE Bastrop-North 3 8082 ANR-Slaughters 3 2061 Bee-Hunter 3 2072 Blair 2 8124 Dyersburg 3 2373 Har-Ken/Addison-G #1 3 2352 Har-Ken/Cox 3 2367 Har-Ken/I.C.C. #9 3 2376 Har-Ken/I.C.C. #12 3 2379 Har-Ken/I.C.C. #15 3 2022 Har-Ken/I.C.C. #16 3 2381 Har-Ken/I.C.C. #17 3 9530 Har-Ken/Murray 3 2362 Har-Ken/P. Gannon Est. #1 3 2351 Har-Ken/Qualls 3 2966 Har-Ken/Stearman #1 3 2960 Har-Ken/W. Ky. #1 3 2962 Har-Ken/W. Ky. #2 3 2375 Har-Ken/W. Ky. #6 3 2087 Heathville-Trenton 1 9303 Helena #2 3 9876 Hux Oil-Russellville 4 1715 Lebanon-Columbia 4 1247 Lebanon-Congas 4 1859 Lebanon-Texas Eastern 3 9527 Liberty-South Hill 3 8073 Midwestern-Whitesville 1 3801 Pooling Receipt-Zone 1 3 9525 Pride Energy No. 1 3 9141 Reynolds-Narge Creek 3 5800 Slaughters-Storage Complex (Withdraw) 1 2648 Spears 3 9404 United Cities-Barnsley Eunice-Zone SL/1 Line SL 9035 ANR-Eunice SL 9084 Bayou Pompey 17 SL 8107 Evangeline SL 8046 Mamou SL 3800 Pooling Receipt-Zone SL SL 3900 SL Lateral Terminus Zone SL/1 Line-Bastrop 1 2020 Arkla-Perryville 1 9870 Channel Explo.-Chicksaw Creek 1 9826 Delhi-Ewing 1 2361 Guffey-Millhaven 1 9877 Hadson-Olla/Summerville 1 9814 Hogan-Davis Lake 1 8063 Pineville (LIG) 1 9832 Wintershall-Clarks 18 CONTRACT NO. T6487 Contract Demand 8,000 MMBtu/D EXHIBIT "B" POINT(S) OF DELIVERY Meter MAOP MDP* No. Name/Description Facilities (psig) (psig) - -------------------------------------------------------------------------------- 1529 Louisville Gas and Electric Company BARDSTOWN ROAD - Latitude 38-12-0, (1) 674 400 Longitude 85-36-0, Jefferson County, KY BEDFORD-LG&E - Latitude 38-34-30, Longitude 85-18-15, Trimble County, KY (1) 810 400 CRESTWOOD - LG&E-Latitude 38-20-0, Longitude 85-25-15, Oldham County, KY (1) 810 400 DOE RUN - Latitude 37-55-30, Longitude 86-2-30, Meade County, KY (1) 810 400 ELDER PARK - Latitude 38-22-0, Longitude 85-25-0, Oldham County, KY (1) 810 400 ELLINGSWORTH LANE - Latitude 38-13-15, Longitude 85-33-0, Jefferson County, KY (1) 810 350 LA GRANGE - Latitude 38-24-0, Longitude 85-24-15, Oldham County, KY (1) 810 400 PENILE ROAD - Latitude 38-6-0, Longitude 85-47-0, Jefferson County, KY (1) 674 400 PRESTON STREET ROAD - Latitude 38-9-45, Longitude 85-41-30, Jefferson County, KY (1) 674 400 19 CONTRACT NO. T6487 FIRM TRANSPORTATION AGREEMENT SUMMER SEASON - EXHIBIT "C" SUPPLY LATERAL CAPACITY LOUISVILLE GAS AND ELECTRIC COMPANY Preferential Rights Supply Lateral MMBtu/d Zone 1 Supply Lateral(s) ------------------------ North Louisiana Leg: 0 Total Zone 1: 0 Zone SL Supply Lateral(s) ------------------------- East Leg: 0 Southeast Leg: 0 South Leg: 12,949 Southwest Leg: 7,297 West Leg: 0 WC-294: 0 HIOS 12,303 ------ Total Zone SL: 32,549 ------ Grand Total: 32,549 ------ This exhibit reflects the combined total supply lateral capacity held by Louisville Gas and Electric Company under the 2-year, 5-year and 8-year agreements for Contract No. T6487. Amendments in contract quantities in either the 2-year, 5-year or 8-year agreements will result in amendment of this exhibit. 20 STANDARD FACILITIES KEY (1) Measurement facilities are owned, operated, and maintained by Texas Gas Transmission Corporation. (2) Measurement facilities are owned, operated, and maintained by ANR Pipeline Company. (3) Measurement facilities are owned, operated, and maintained by Arkansas Louisiana Gas Company. (4) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Kerr-McGee Corporation. (5) Measurement facilities are owned, operated, and maintained by Koch Gateway Pipeline Company. (6) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Delhi Gas Pipeline Corporation. (7) Measurement facilities are owned, operated and maintained by Kerr-McGee Corporation. (8) Measurement facilities are owned, operated, and maintained by Louisiana Intrastate Gas Corporation. (9) Measurement facilities are owned, operated, and maintained by Trunkline Gas Company. (10) Measurement facilities are owned, operated, and maintained by Columbia Gulf Transmission Company. (11) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Columbia Gulf Transmission Company. (12) Measurement facilities are owned, operated, and maintained by Florida Gas Transmission Company. (13) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by ANR Pipeline Company. (14) Measurement facilities are owned by Champlin Petroleum Company and operated and maintained by ANR Pipeline Company. (15) Measurement facilities are owned by Transcontinental Gas Pipe Line Corporation and operated and maintained by ANR Pipeline Company. (16) Measurement facilities are jointly owned by others and operated and maintained by ANR Pipeline Company. (17) Measurement facilities are owned by Koch Gateway Pipeline Company and operated and maintained by ANR Pipeline Company. (18) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Texas Eastern Transmission Corporation. (19) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Natural Gas Pipeline Company of America. (20) Measurement facilities are owned by Louisiana Intrastate Gas Corporation and operated and maintained by Texas Gas Transmission Corporation. (21) Measurement facilities are owned, operated, and maintained by Texas Eastern Transmission Corporation. (22) Measurement facilities are owned by Kerr-McGee Corporation and operated and maintained by ANR Pipeline Company. (23) Measurement facilities are operated and maintained by ANR Pipeline Company. 21 (24) Measurement facilities are owned, operated, and maintained by Transcontinental Gas Pipe Line Corporation. (25) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Tennessee Gas Pipeline Company. (26) Measurement facilities are owned, operated, and maintained by Northern Natural Gas Company. (27) Measurement facilities are owned and maintained by Faustina Pipeline Company and operated by Texas Gas Transmission Corporation. (28) Measurement facilities are owned by Samedan and operated and maintained by ANR Pipeline Company. (29) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by CNG Producing. (30) Measurement facilities are owned, operated, and maintained by Devon Energy Corporation. (31) Measurement facilities are owned by Total Minatome Corporation and operated and maintained by Texas Gas Transmission Corporation. (32) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Trunkline Gas Company. (33) Measurement facilities are owned by Linder Oil Company and operated and maintained by Texas Gas Transmission Corporation. (34) Measurement facilities are owned, operated, and maintained by Mississippi River Transmission Corporation. (35) Measurement facilities are owned, operated, and maintained by Texaco Inc. (36) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Louisiana Resources Company. (37) Measurement facilities are owned, operated, and maintained by Louisiana Resources Company. (38) Measurement facilities are owned by Oklahoma Gas Pipeline Company and operated and maintained by ANR Pipeline Company. (39) Measurement and interconnecting pipeline facilities are owned and maintained by Louisiana Resources Company. The measurement facilities are operated and flow controlled by Texas Gas Transmission Corporation. (40) Measurement facilities are owned by Hall-Houston and operated and maintained by ANR Pipeline Company. (41) Measurement facilities are owned, operated, and maintained as specified in Exhibit "B". (42) Measurement facilities are owned by Enron Corporation and operated and maintained by Texas Gas Transmission Corporation. (43) Measurement facilities are owned by United Cities Gas Company and operated and maintained by TXG Engineering, Inc. (44) Measurement facilities are owned, operated, and maintained by NorAm Gas Transmission Company. (45) Measurement facilities are owned by Falcon Seaboard Gas Company and operated and maintained by Texas Gas Transmission Corporation. (46) Measurement facilities are owned by ANR Pipeline Company and operated and maintained by High Island Offshore System. 22 (47) Measurement facilities are owned by Forest Oil Corporation, et al., and operated and maintained by Tenneco Gas Transportation Company. (48) Measurement facilities are owned by PSI, Inc., and operated and maintained by ANR Pipeline Company. (49) Measurement facilities are owned, operated, and maintained by Tennessee Gas Pipeline Company. (50) Measurement facilities are owned, operated, and maintained by Colorado Interstate Gas Company. (51) Measurement facilities are owned by Producer's Gas Company and operated and maintained by Natural Gas Pipeline Company of America. (52) Measurement facilities are owned by Zapata Exploration and operated and maintained by ANR Pipeline Company. (53) Measurement facilities are jointly owned by Amoco, Mobil, and Union; operated and maintained by ANR Pipeline Company. (54) Measurement facilities are owned, operated, and maintained by VHC Gas Systems, L.P. (55) Measurement facilities are owned by Walter Oil and Gas and operated and maintained by Columbia Gulf Transmission Company. (56) Measurement facilities are operated and maintained by Natural Gas Pipeline Company of America. (57) Measurement facilities are operated and maintained by Texas Gas Transmission Corporation. (58) Measurement facilities are operated and maintained by Tennessee Gas Pipeline Company. (59) Measurement facilities are operated and maintained by Columbia Gulf Transmission Company. (60) Measurement facilities are owned, operated, and maintained by Midwestern Gas Transmission Company. (61) Measurement facilities are owned, operated, and maintained by Western Kentucky Gas Company. 23 EX-10.42 4 EXHIBIT 10.42 EXHIBIT 10.42 THIS AGREEMENT shall be effective as of the 1st day of November, 1996, by and between TENNESSEE GAS PIPELINE COMPANY, a Delaware Corporation, hereinafter referred to as "Transporter" and LOUISVILLE GAS & ELECTRIC O., a KENTUCKY Corporation, hereinafter referred to as "Shipper." Transporter and Shipper shall collectively be referred to herein as the "Parties." ARTICLE I DEFINITIONS 1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily quantity of gas which Transporter agrees to receive and transport on a firm basis, subject to Article II herein, for the account of Shipper hereunder on each day during each year during the term hereof, which shall be 30,000 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit "A" attached hereto. 1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of the General Terms and Conditions of Transporter's FERC Gas Tariff. ARTICLE II TRANSPORTATION Transportation Service - Transporter agrees to accept and receive daily on a firm basis, at the Point(s) of Receipt from Shipper or for Shipper's account such quantity of gas as Shipper makes available up to the Transportation Quantity, and to deliver to or for the account of Shipper to the Point(s) of Delivery an Equivalent Quantity of gas. ARTICLE III POINT(S) OF RECEIPT AND DELIVERY The Primary Point(s) of Receipt and Delivery shall be those points specified on Exhibit "A" attached hereto. ARTICLE IV All Facilities are or shall be in place as of the service commencement date to render the service provided for in this Agreement. ARTICLE V QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT For all gas received, transported and delivered hereunder the Parties agree to the Quality Specifications and Standards for Measurement as specified in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. ARTICLE VI RATES AND CHARGES FOR GAS TRANSPORTATION 6.1 TRANSPORTATION RATES - Commencing upon the effective date hereof, the rates, charges, and surcharges to be paid by Shipper to Transporter for the transportation service provided herein shall be in accordance with Transporter's Rate Schedule FT-A and the General Terms and Conditions of Transporter's FERC Gas Tariff. 6.2 INCIDENTAL CHARGES - Shipper agrees to reimburse Transporter for any filing or similar fees, which have not been previously paid for by Shipper, which Transporter incurs in rendering service hereunder. 6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that Transporter shall have the unilateral right to file with the appropriate regulatory authority and make effective changes in (a) the rates and charges applicable to service pursuant to Transporter's Rate Schedule FT-A, (b) the rate schedule(s) pursuant to which service hereunder is rendered, or (c) any provision of the General Terms and Conditions applicable to those rate schedules. Transporter agrees that Shipper may protest or contest the aforementioned filings, or may seek authorization from duly constituted regulatory authorities for such adjustment of Transporter's existing FERC Gas Tariff as may be found necessary to assure Transporter just and reasonable rates. ARTICLE VII BILLINGS AND PAYMENT Transporter shall bid and Shipper shall pay all rates and charges in accordance with Articles V and VI, respectively, of the General Terms and Conditions of Transporter's FERC Gas Tariff. 2 ARTICLE VIII GENERAL TERMS AND CONDITIONS This Agreement shall be subject to the effective provisions of Transporter's Rate Schedule FT-A and to the General Terms and Conditions incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC. ARTICLE IX REGULATION 9.1 This Agreement shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Agreement shall be void and of no force and effect if any necessary regulatory approval is not so obtained or continued. All Parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no Party shall be liable to any other Party for failure to obtain or continue such approvals or authorizations. 9.2 The transportation service described herein shall be provided subject to Subpart G, Part 284, of the FERC Regulations provided however, that Transporter shall initiate and provide service to Shipper under Subpart B, Part 284, of the FERC Regulations until such time as the Commission authorizes service under Subpart G. ARTICLE X RESPONSIBILITY DURING TRANSPORTATION Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. ARTICLE XI WARRANTIES 11.1 In addition to the warranties set forth in Article IX of the General Terms and Conditions of Transporter's FERC Gas Tariff, Shipper warrants the following: 3 (a) Shipper warrants that all upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the receipt and delivery points under this Agreement and any quantity limitations for each point as specified on Exhibit "A" attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to receive or deliver gas as contemplated by this Agreement. (b) Shipper agrees to indemnify and hold Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including reasonable attorneys fees) arising from or out of breach of any warranty by Shipper herein. 11.2 Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty. ARTICLE XII TERM 12.1 This Agreement shall be effective as of the 1st day of November, 1996, the service commencement date, and shall remain in force and effect until the 31st day of October, 2001, ("Primary Term") and on a year to year basis thereafter unless terminated by Shipper upon at least one year prior written notice to Transporter. If the FERC or other governmental body having jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement shall terminate on the abandonment date permitted by the FERC or such other governmental body. Tennessee warrants that it will not file for abandonment of this service during the Primary Term or any renewal term for a period of at least five years after the expiration of the Primary Term. 12.2 Any portions of this Agreement necessary to resolve or cash-out imbalances under this Agreement as required by the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1, shall survive the other parts of this Agreement until such time as such balancing has been accomplished; provided, however, that Transporter notifies Shipper of such imbalance no later than twelve months after the termination of this Agreement. 4 12.3 This Agreement will terminate automatically upon written notice from Transporter in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accord with the terms and conditions of Article VI of the General Terms and Conditions of Transporter's FERC Tariff. ARTICLE XIII NOTICE Except as otherwise provided in the General Terms and Conditions applicable to this Agreement, any notice under this Agreement shall be in writing and mailed to the post office address of the Party intended to receive the same, as follows: TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY P.O. Box 2511 Houston, Texas 77252-2511 Attention: Transportation Marketing SHIPPER: NOTICES: LOUISVILLE GAS & ELECTRIC CO. P.O. BOX 32020 LOUISVILLE, KY 40232 Attention: CLAY MURPHY, MGR - GAS SUPPLY BILLING: LOUISVILLE GAS & ELECTRIC CO. P.O. BOX 32020 LOUISVILLE, KY 40232 Attention: CLAY MURPHY, MGR - GAS SUPPLY or to such other address as either Party shall designate by formal written notice to the other. ARTICLE XIV ASSIGNMENTS 14.1 Either Party may assign or pledge this Agreement and all rights and obligations hereunder under the provisions of any mortgage, deed of trust, indenture, or other instrument which it has executed or may execute hereafter as security for indebtedness. Either Party may, without relieving itself of its obligation under this Agreement, assign any of its rights hereunder to a company with which it is affiliated. Otherwise, Shipper shall not assign this 5 Agreement or any of its rights hereunder, except in accord with Article III, Section 11 of the General Terms and Conditions of Transporter's FERC Gas Tariff. 14.2 Any person which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of either Party hereto shall be entitled to the rights and shall be subject to the obligations of its predecessor in interest under this Agreement. ARTICLE XV MISCELLANEOUS 15.1 The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Texas, without regard to the doctrines governing choice of law. 15.2 If any provisions of this Agreement is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable at either Party's option; and if the severability option is exercised, the remaining provisions of the Agreement shall remain in full force and effect. 15.3 Unless otherwise expressly provided in this Agreement or Transporter's Gas Tariff, no modification of or supplement to the terms and provisions stated in this agreement shall be or become effective until Shipper has submitted a request for change through the TENN-SPEED 2 of Transporter's agreement to such change. 15.4 Exhibit "A" attached hereto is incorporated herein by reference and made a part hereof for all purposes. 15.5 Notwithstanding Section XXX of the General Terms & Conditions of TGP's FERC Gas Tariff, in the event of a conflict between this Agreement or any modification thereto, and the General Terms & Conditions of TGP's FERC Gas Tariff, this Agreement or any modification thereto shall prevail. 15.6 This agreement shall be subject to modification by written agreement between Shipper and Transporter. IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed. TENNESSEE GAS PIPELINE COMPANY 6 By: _______________________________ Its: _______________________________ LOUISVILLE GAS & ELECTRIC CO. By: __________________________ Title: __________________________ Date: __________________________ 7 GAS TRANSPORTATION AGREEMENT (or Use Under oT-A Rate Schedule) Exhibit "A" AMENDMENT #0 TO GAS TRANSPORTATION AGREEMENT DATED November 1, 1996 BETWEEN TENNESSEE GAS PIPELINE COMPANY AND LOUISVILLE GAS & ELECTRIC CO. LOUISVILLE GAS & ELECTRIC CO. EFFECTIVE DATE OF AMENDMENT: November 1, 1996 RATE SCHEDULE: FT-A SERVICE PACKAGE: 10609 SERVICE PACKAGE TQ: 30,000 Dth METER METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE R/D LEG METER-TQ BILLABLE-TQ 011306 CHANNEL-AGUA DULCE EXCH CHANNEL INDUSTRIES GAS CO NUECES TX 00 R 100 18,000 18,000 020743 STA 834 POOLING POINT FRANKLIN LA 01 R 800 12,000 12,000 Total Receipt TQ: 30,000 30,000 020001 COLUMBIA UF-BR RUN COBB W VA COLUMBIA GAS TRANSMISSION CORP KANAWHA WV 03 D 087 30,000 30,000
NUMBER OF RECEIPT POINTS AFFECTED: 2 NUMBER OF DELIVERY POINTS AFFECTED: 1 Note: Exhibit "A" is a reflection of the contract and all amendments as of the amendment effective date 8 EX-10.46 5 EXHIBIT 10.46 CONTRACT 96-205-026 EXHIBIT 10.46 SPOT COAL SUPPLY AGREEMENT This is a spot coal supply agreement (the "Agreement") dated June 1, 1996 between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West Main Street, Louisville, Kentucky 40202 ("Buyer") and KINDILL MINING, INC., an Indiana corporation, 101 Court Street, Suite 106, Evansville, Indiana 47708 ("Seller"). The parties hereto agree as follows: SECTION 1. GENERAL Seller will sell to Buyer and Buyer will buy from Seller steam coal under all the terms and conditions of this Agreement. SECTION 2. TERM The term of this Agreement shall commence on June 1, 1996 and shall continue through December 31, 1996. SECTION 3. QUANTITY; OPTION SECTION 3.1 Quantity. Seller shall sell and deliver and Buyer shall purchase and accept delivery of 100,000 tons of coal per month. Such coal shall be delivered in accordance with reasonable delivery schedules to be submitted by Buyer as necessary. SECTION 3.2 Option. (a) Buyer shall have an option (the "Option") to extend the term of this Agreement through December 31, 1997 (the period January 1, 1997 to December 31, 1997 1 CONTRACT #96-205-026 being hereinafter referred to as the "Option Period") under the terms and conditions set forth in subsection (b) below. Buyer shall exercise the Option by giving notice to Seller ("the Option Notice") by November 1, 1996 of its exercise of the Option. (b) If Buyer exercises the Option: (i) The quantity to be delivered hereunder during the Option Period shall be as designated by Buyer in its Option Notice but shall be no greater than one million tons and no less than 750,000 tons. Such coal shall be delivered ratably over the Option Period in accordance with reasonable delivery schedules to be submitted by Buyer as necessary. (ii) The base price of the coal to be sold and purchased during the Option Period will be $.70500/MMBTU. (iii) Except as specifically set forth in (i) and (ii) above, all provisions of this Agreement shall remain in effect during the Option Period. SECTION 4. SOURCE SECTION 4.1 Source. The coal sold hereunder shall be supplied from geological seams Indiana 5 and 6, Kindill 1 and 2 Mines, Pike County, Indiana (the "Coal Property"). SECTION 4.2 Assurance of Operation and Reserves. Seller represents and warrants that the Coal Property contains economically recoverable coal of a quality and in quantities which will be sufficient to satisfy all the requirements of this Agreement. SECTION 4.3 Substitute Coal. Notwithstanding the above representations and warranties, in the event that Seller is unable to produce or obtain coal from the Coal Property in the quantity and 2 CONTRACT #96-205-026 of the quality required by this Agreement, and such inability is not caused by a force majeure event as defined in SECTION 10, then Buyer will have the option of requiring that Seller supply substitute coal from other facilities and mines under all the terms and conditions of this Agreement including, but not limited to, the price provisions of SECTION 8, the quality specifications of SECTION 6.1, and the provisions of SECTION 5 concerning reimbursement to Buyer for increased transportation costs. Seller's delivery of coal not produced from the Coal Property without having received the express written consent of Buyer shall constitute a material breach of this Agreement. SECTION 5. DELIVERY SECTION 5.1 RAIL DELIVERY. The coal shall be delivered to Buyer F.O.B. railcar at the rail loading facility near Enosville, Indiana on the Norfolk Southern Railway (the "Delivery Point"). Seller may deliver the coal at a location different from the Delivery Point, provided, however, that Seller shall reimburse Buyer for any resulting increases in the cost of transporting the coal to Buyer's generating stations. Any resulting savings in such transportation costs shall be retained by Buyer. Title to and risk of loss respecting coal will pass to Buyer and the coal will be considered to be delivered when it is loaded into the railcars at the rail loading facility. Buyer or its contractor shall furnish suitable railcars in accordance with a delivery schedule provided by Buyer to Seller. Seller shall be responsible for and pay the cost of repairs for any damages caused by Seller to railcars owned or leased by Buyer while such railcars are in Seller's control 3 CONTRACT #96-205-026 or custody. Seller shall comply with the applicable provisions of Buyer's rail contractor's tariff. SECTION 5.2 Freeze Conditioning. At Buyer's request, Seller shall treat (or have treated) any shipment of coal hereunder with a freeze conditioning agent approved by Buyer in order to maintain coal handling characteristics during shipment. If requested by Buyer, Seller shall also treat (or have treated) any railcars specified by Buyer with a side release agent approved by Buyer. The price for each such requested chemical treatment shall be one dollar ($1) per gallon for each application of freeze conditioning agent or side release agent, as the case may be. Seller shall invoice Buyer for all such treatments which occur in a calendar month by the fifteenth of the following month; and payment shall be mailed by the 25th of such following month or within ten days after receipt of Seller's invoice, whichever is later. SECTION 6. QUALITY SECTION 6.1 Specifications. The coal delivered hereunder shall conform to the following specifications on an "as received" basis: Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) - -------------------------------------------------------------------------------- BTU/LB. min. 11,000 < 10,700 LBS/MMBTU: ---------- MOISTURE max. 13.0 > 14.0 ASH max. 9.0 > 10.5 SULFUR max. 3.1 > 3.3 SULFUR min. 2.2 < 2.0 CHLORINE max. 0.05 > 0.10 FLUORINE max. 0.006 > .01 NITROGEN max. 1.20 > 1.50 ASH/SULFUR RATIO min. 2.5:1 < 2.5:1 4 CONTRACT #96-205-026 Size (3" x 0"): Top size (inches)* max. 3x0 > 3x0 Fines (% by wgt) Passing 1/4" screen max. 45 > 55 % BY WEIGHT: ------------ VOLATILE max. 38 > 40 VOLATILE min. 30 < 29 FIXED CARBON max. 46 > 48 FIXED CARBON min. 35 < 30 GRINDABILITY (HGI) min. 52 < 50 BASE ACID RATIO (B/A) max. .50 > .60 SLAGGING FACTOR** max. 1.90 > 2.10 FOULING FACTOR*** max. 0.50 > 1.00 ASH FUSION TEMPERATURE ((DEG.)F) (ASTM D1857) ----------------------------------------------- REDUCING ATMOSPHERE ------------------- Initial Deformation min. 1950F min. 1900F Softening (H=W) min. 2005F min. 1975F Softening (H=1/2W) min. 2050F min. 2000F Fluid min. 2135F min. 2100F OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2300F min. 2200F Softening (H=W) min. 2330F min. 2280F Softening (H=1/2W) min. 2425F min. 2300F Fluid min. 2490F min. 2375F * All the coal will be of such size that it will pass through a screen having circular perforations three (3) inches in diameter, but shall not contain more than forty-five percent (45%) by weight of coal that will pass through a screen having circular perforations one-quarter (1/4) of an inch in diameter. ** Slagging Factor (R(s))=(B/A) x (Percent Sulfur by Weight(Dry)) 5 CONTRACT #96-205-026 *** Fouling Factor (R(f))=(B/A) x (Percent Na(2)0 by Weight(Dry)) The Base Acid Ratio (B/A) is herein defined as: BASE ACID RATIO (B/A) = (Fe(2)0(3) + Ca0 + Mg0 + Na(2)0 + K(2)0) ---------------------------------------- (Si0(2) + A1(2)0(3) + T10(2)) Note: As used herein > means greater than: < means less than. SECTION 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall mean one barge load, a barge lot load, or one unit trainload, in accordance with Buyer's actual sampling and analyzing practices. SECTION 6.3 REJECTION. Buyer has the right, but not the obligation, to reject any shipment which fail(s) to conform to the Rejection Limits set forth in SECTION 6.1 or contains extraneous materials. Buyer must reject such coal within seventy-two (72) hours of receipt of the coal analysis provided for in SECTION 7.2 or such right to reject is waived. In the event Buyer rejects such non-conforming coal, Buyer shall return the coal to Seller or, at Seller's request, divert such coal to Seller's designee, all at Seller's cost. Seller shall replace the rejected coal within five (5) working days from notice of rejection with coal conforming to the Rejection Limits set forth in SECTION 6.1. If Seller fails to replace the rejected coal within such five (5) working day period or the replacement coal is rightfully rejected, Buyer may purchase coal from another source in order to replace the rejected coal. Seller shall reimburse Buyer for (i) any amount by which the actual price plus transportation costs to Buyer of such coal purchased from another source exceed the price of such coal under this Agreement (as adjusted under SECTION 8.3 for coal of the 6 CONTRACT #96-205-026 quality actually supplied by the other source) plus transportation costs to Buyer from the Delivery Point; and (ii) any and all transportation, storage, handling, or other expenses that have been incurred by Buyer for rightfully rejected coal. This remedy is in addition to all of Buyer's other remedies under this Agreement and under applicable law and in equity for Seller's breach. If Buyer fails to reject a shipment of non-conforming coal which it had the right to reject for failure to meet any or all of the Rejection Limits set forth in SECTION 6.1 or because such shipment contained extraneous materials, then such non-conforming coal shall be deemed accepted by Buyer; however, the price shall be adjusted in accordance with SECTION 8.3 and the quantity Buyer is obligated to purchase from Seller, at Buyer's sole option, shall be reduced by the amount of each such non-conforming shipment. Further, for shipments containing extraneous materials, which include, but are not limited to, slate, rock, wood, corn husks, mining materials, metal, steel, etc., the estimated weight of such materials shall be deducted from the weight of that shipment. SECTION 6.4 SUSPENSION AND TERMINATION. If the coal sold hereunder fails to meet one or more of the Guaranteed Monthly Weighted Averages set forth in SECTION 6.1 for any one month during the term of this Agreement, or if 3 barge shipments in a 7 day period are rejectable by Buyer, of if Buyer receives at generating station(s) 2 rail shipments which are rejectable in any 10 day period, Buyer may, upon notice confirmed in writing and sent to Seller by certified mail, terminate this Agreement 7 CONTRACT #96-205-026 and exercise all its other rights and remedies under applicable law and in equity for Seller's breach. SECTION 7. WEIGHTS, SAMPLING AND ANALYSIS SECTION 7.1 Weights. The weight of the coal delivered hereunder shall be determined on a per shipment basis by Buyer on the basis of scale weights at the generating station(s) unless another method is mutually agreed upon by the parties. Such scales shall be duly certified by an appropriate testing agency and maintained in an accurate condition. Seller shall have the right, at Seller's expense and upon reasonable notice, to have the scales checked for accuracy at any reasonable time or frequency. If the scales are found to be inaccurate, over or under the tolerance range allowable for the scale, either party shall pay to the other any amounts owed due to such inaccuracy for a period not to exceed thirty (30) days before the time any inaccuracy of scales is determined. SECTION 7.2 Sampling and Analysis. The sampling and analysis of the coal delivered hereunder shall be performed by Buyer and the results thereof shall be accepted and used for the quality and characteristics of the coal delivered under this Agreement. All analyses shall be made in Buyer's laboratory at Buyer's expense in accordance with reliable and industry accepted standards. Samples for analyses shall be taken by any reliable and industry accepted standard acceptable to both parties, may be composited, and shall be taken with a frequency and regularity sufficient to provide reasonably accurate representative samples of the deliveries made hereunder. Seller represents that it is familiar with Buyer's sampling and analysis practices, and finds them to be acceptable. Buyer shall notify Seller in writing of any 8 CONTRACT #96-205-026 significant changes in Buyer's sampling and analysis practices. Any such changes in Buyer's sampling and analysis practices shall, except for industry accepted changes in practices, provide for no less accuracy than the sampling and analysis practices existing at the time of the execution of this Agreement, unless the Parties otherwise mutually agree. Each sample taken by Buyer shall be divided into 4 parts and put into airtight containers, properly labeled and sealed. One part shall be used for analysis by Buyer; one part shall be used by Buyer as a check sample, if Buyer in its sole judgment determines it is necessary; one part shall be retained by Buyer until the 25th of the month following the month of unloading (the "Disposal Date") and shall be delivered to Seller for analysis if Seller so requests before the Disposal Date; and one part ("Referee Sample") shall be retained by Buyer until the Disposal Date. Seller shall be given copies of all analyses made by Buyer by the 12th day of the month following the month of unloading. Seller, on reasonable notice to Buyer shall have the right to have a representative present to observe the sampling and analyses performed by Buyer. Unless Seller requests a Referee Sample analysis before the Disposal Date, Buyer's analysis shall be used to determine the quality of the coal delivered hereunder. The Monthly Weighted Averages shall be determined by utilizing the individual shipment analyses. If any dispute arises before the Disposal Date, the Referee Sample retained by Buyer shall be submitted for analysis to an independent commercial testing laboratory ("Independent Lab") mutually chosen by Buyer and Seller. For each coal quality specification in question, a dispute shall be deemed not to exist and Buyer's analysis shall prevail and the analysis of the 9 CONTRACT #96-205-026 Independent Lab shall be disregarded if the analysis of the Independent Lab differs from the analysis of Buyer by an amount equal to or less than: (i) 0.50% moisture (ii) 0.50% ash on a dry basis (iii) 100 Btu/lb. on a dry basis (iv) 0.10% sulfur on a dry basis. For each coal quality specification in question, if the analysis of the Independent Lab differs from the analysis of Buyer by an amount more than the amounts listed above, then the analysis of the Independent Lab shall prevail and Buyer's analysis shall be disregarded. The cost of the analysis made by the Independent Lab shall be borne by Seller to the extent that Buyer's analysis prevails and by Buyer to the extent that the analysis of the Independent Lab prevails. SECTION 8. PRICE SECTION 8.1 Price. The base price (the "Base Price") of the coal to be sold hereunder will be $.70000/MMBTU. SECTION 8.2 Quality Price Adjustments. (a) The Base Price is based on coal meeting or exceeding the Guaranteed Monthly Weighted Average specifications as set forth in SECTION 6.1. Quality price discounts shall be applied for each specification each month to reflect failures to meet the Guaranteed Monthly Weighted Averages set forth in SECTION 6.1, as determined pursuant to SECTION 7.2, subject to the provisions set forth below. The discount values used are as follows: 10 CONTRACT #96-205-026 DISCOUNT VALUES --------------- $/MMBTU ------- BTU/LB 0.2604 $/LB./MMBTU ----------- SULFUR 0.1232 ASH 0.0083 MOISTURE 0.0016 (b) Notwithstanding the foregoing, for each specification each month, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. However, if the actual Monthly Weighted Average fails to meet such applicable Discount Point, then the discount shall be calculated on the basis of the difference between the actual Monthly Weighted Average and the Guaranteed Monthly Weighted Average pursuant to the methodology shown in Exhibit A attached hereto. Guaranteed Monthly Weighted Average Discount Point ---------------- -------------- BTU/LB min.11,000 10,700 LB/MMBTU - --------- SULFUR max. 3.1 3.2 ASH max. 9.0 9.5 MOISTURE max. 13.0 14.0 For example, if the actual Monthly Weighted Average of ash equals 10.0 lb/MMBTU, then the applicable discount would be (10.0 lb. - 9.0 lb.) x $0.0083/lb./MMBTU = $.0083/MMBTU. 11 CONTRACT #96-205-026 SECTION 8.3 PAYMENT CALCULATION. Exhibit A attached hereto shows the methodology for calculating the coal payment and quality price discounts for the month Seller's coal was unloaded by Buyer. If there are any such discounts, Buyer shall apply credit to amounts owed Seller for the month the coal was unloaded. SECTION 9. INVOICES, BILLING AND PAYMENT. SECTION 9.1 INVOICING ADDRESS. Invoices will be sent to Buyer at the following address: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Director, Fuels Procurement and Delivery With a copy to: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Manager, Accounts Payable SECTION 9.2 Invoice Procedures for Coal Shipments. Seller shall invoice Buyer at the Base Price, minus any quality price discounts, for all coal unloaded in a calendar month by the fifteenth of the following month. SECTION 9.3 Payment Procedures for Coal Shipments. Payment for coal unloaded in a calendar month shall be mailed by the 25th of the month following the month of unloading or within ten days after receipt of Seller's invoice, whichever is later. Buyer shall mail all 12 CONTRACT #96-205-026 payments to Seller's account at P.O. Box 845, 313 Frederica Street, Suite 301, Owensboro, Kentucky 42302, Attn: Rhonda Cavender. SECTION 9.4 Withholding. Buyer shall have the right to withhold from payment of any billing or billings (i) any sums which it is not able in good faith to verify or which it otherwise in good faith disputes, (ii) any damages resulting from or likely to result from any breach of this Agreement by Seller, and (iii) any amounts owed to Buyer from Seller. Buyer shall notify Seller promptly in writing of any such issue, stating the basis of its claim and the amount it intends to withhold. Payment by Buyer, whether knowing or inadvertent, of any amount in dispute shall not be deemed a waiver of any claims or rights by Buyer with respect to any disputed amounts or payments made. SECTION 10. FORCE MAJEURE If either party hereto is delayed in or prevented from performing any of its obligations or from utilizing the coal sold under this Agreement due to acts of God, war, riots, civil insurrection, acts of the public enemy, strikes, lockouts, fires, floods, earthquakes, or the failure of Norfolk Southern Railway Company ("NS") to transport the coal from the Delivery Point for any reason other than Buyer's breach of its agreement with NS, which are beyond the reasonable control and without the fault or negligence of the party affected thereby, then the obligations of both parties hereto shall be suspended to the extent made necessary by such event; provided that the affected party gives written notice to the other party as early as practicable of the nature and probable duration of the force majeure event. The party declaring 13 CONTRACT #96-205-026 force majeure shall exercise due diligence to avoid and shorten the force majeure event and will keep the other party advised as to the continuance of the force majeure event. During any period in which Seller's ability to perform hereunder is affected by a force majeure event, Seller shall not deliver any coal to any other buyers to whom Seller's ability to supply is similarly affected by such force majeure event unless contractually committed to do so at the beginning of the force majeure event; and further shall deliver to Buyer under this Agreement at least a pro-rata portion (on a per ton basis) of its total contractual commitments to all its buyers to whom Seller's ability to supply is similarly affected by such force majeure event in place at the beginning of the force majeure event. An event which affects the Seller's ability to produce or obtain coal from a mine other than the Coal Property will not be considered a force majeure event hereunder. Tonnage deficiencies resulting from a force majeure event shall be made up at Buyer's sole option on a reasonable schedule. SECTION 11. NOTICES SECTION 11.1 Form and Place of Notice. Any official notice, request for approval or other document required to be given under this Agreement shall be in writing, unless otherwise provided herein, and shall be deemed to have been sufficiently given when delivered in person, transmitted by facsimile or other electronic media, delivered to an established mail service for same day or overnight delivery, or dispatched in the United States mail, postage prepaid, for mailing by first class, certified, or registered mail, return receipt requested, and addressed as follows: 14 CONTRACT #96-205-026 If to Buyer: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, Kentucky 40232 Attn: Director, Fuels Procurement and Delivery with a copy to: Louisville Gas and Electric Company 820 West Broadway P.O. Box 32020 Louisville, Kentucky 40232 Attn: Manager, Procurement Services If to Seller: Kindill Mining, Inc. 101 Court Street, Suite 106 Evansville, Indiana 47708 Attn: Sales Manager SECTION 11.2 CHANGE OF PERSON OR ADDRESS. Either party may change the person or address specified above upon giving written notice to the other party of such change. SECTION 12. RIGHT TO SELL Buyer shall have the unqualified right to sell all or any of the coal purchased under this Agreement. SECTION 13. INDEMNITY AND INSURANCE SECTION 13.1 INDEMNITY. Seller agrees to indemnify and save harmless Buyer, its officers, directors, employees and representatives from any responsibility and liability for any and all claims, demands, losses, legal actions for personal injuries, property damage and pollution (including reasonable attorney's fees) (i) relating to the barges or railcars provided by Buyer or Buyer's contractor while such barges or railcars are in the care and custody of the loading dock or loading facility, (ii) due to any failure of Seller to comply with laws, regulations or ordinances, or (iii) due to the acts or omissions of Seller in the performance of this Agreement. 15 CONTRACT #96-205-026 SECTION 13.2 Insurance. Seller agrees to carry insurance coverage with minimum limits as follows: (1) Commercial General Liability, including Completed Operations and Contractual Liability, $1,000,000 single limit liability. (2) Automobile General Liability, $1,000,000 single limit liability. (3) In addition, Seller shall carry excess liability insurance covering the foregoing perils in the amount of $4,000,000 for any one occurrence. (4) Workers' Compensation and Employer's Liability with statutory limits. If any of the above policies are written on a claims made basis, then the retroactive date of the policy or policies will be no later than the effective date of this Agreement. Certificates of Insurance satisfactory in form to the Buyer and signed by the Seller's insurer shall be supplied by the Seller to the Buyer evidencing that the above insurance is in force and that not less than 30 calendar days written notice will be given to the Buyer prior to any cancellation or material reduction in coverage under the policies. The Seller shall cause its insurer to waive all subrogation rights against the Buyer respecting all losses or claims arising from performance hereunder. Evidence of such waiver satisfactory in form and substance to the Buyer shall be exhibited in the Certificate of Insurance mentioned above. Seller's liability shall not be limited to its insurance coverage. SECTION 14. TERMINATION FOR DEFAULT. Subject to SECTION 6.4, if either party hereto commits a material breach of any of its obligations under this Agreement at any time, then the other party has the right to give written 16 CONTRACT #96-205-026 notice describing such breach and stating its intention to terminate this Agreement no sooner than 15 days after the date of the notice (the "notice period"). If such material breach is curable and the breaching party cures such material breach within the notice period, then the Agreement shall not be terminated due to such material breach. If such material breach is not curable or the breaching party fails to cure such material breach within the notice period, then this Agreement shall terminate at the end of the notice period in addition to all the other rights and remedies available to the aggrieved party under this Agreement and at law and in equity. SECTION 15. TAXES, DUTIES AND FEES Seller shall pay when due, and the price set forth in SECTION 8 of this Agreement shall be inclusive of, all taxes, duties, fees and other assessments of whatever nature imposed by governmental authorities with respect to the transactions contemplated under this Agreement. SECTION 16. DOCUMENTATION AND RIGHT OF AUDIT Seller shall maintain all records and accounts pertaining to payments, quantities, quality analyses and source of all coal supplied under this Agreement for a period lasting through the term of this Agreement and for two years thereafter. Buyer shall have the right at no additional expense to Buyer to audit, copy and inspect such records and accounts at any reasonable time upon reasonable notice during the term of this Agreement and for 2 years thereafter. SECTION 17. EQUAL EMPLOYMENT OPPORTUNITY. To the extent applicable, Seller shall comply with all of the following provisions which are incorporated herein by reference: Equal Opportunity regulations set forth in 41 CRF SECTION 60- 17 CONTRACT #96-205-026 1.4(a) and (c) prohibiting discrimination against any employee or applicant for employment because of race, color, religion, sex, or national origin; Vietnam Era Veterans Readjustment Assistance Act regulations set forth in 41 CRF SECTION 50-250.4 relating to the employment and advancement of disabled veterans and veterans of the Vietnam Era; Rehabilitation Act regulations set forth in 41 CRF SECTION 60-741.4 relating to the employment and advancement of qualified disabled employees and applicants for employment; the clause known as "Utilization of Small Business Concerns and Small Business Concerns Owned and Controlled by Socially and Economically Disadvantaged Individuals" set forth in 15 USC SECTION 637(d)(3); and subcontracting plan requirements set forth in 15 USC SECTION 637(d). SECTION 18. COAL PROPERTY INSPECTIONS Buyer and its representatives, and others as may be required by applicable laws, ordinances and regulations shall have the right at all reasonable times and at their own expense to inspect the Coal Property, including the loading facilities, scales, sampling system(s), wash plant facilities, and mining equipment for conformance with this Agreement. Seller shall undertake reasonable care and precautions to prevent personal injuries to any representatives, agents or employees of Buyer (collectively, "Visitors") who inspect the Coal Property. Any such Visitors shall make every reasonable effort to comply with Seller's regulations and rules regarding conduct on the work site, made known to Visitors prior to entry, as well as safety measures mandated by state or federal rules, regulations and laws. Buyer understands that underground mines and related facilities are inherently high-risk environments. Buyer's failure to inspect the Coal Property or 18 CONTRACT #96-205-026 to object to defects therein at the time Buyer inspects the same shall not relieve Seller of any of its responsibilities nor be deemed to be a waiver of any of Buyer's rights hereunder. SECTION 19. MISCELLANEOUS SECTION 19.1 APPLICABLE LAW. This Agreement shall be construed in accordance with the laws of the State of Kentucky, and all questions of performance of obligations hereunder shall be determined in accordance with such laws. SECTION 19.2 HEADINGS. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning of interpretation of this Agreement. SECTION 19.3 WAIVER. The failure of either party to insist on strict performance of any provision of this Agreement, or to take advantage of any rights hereunder, shall not be construed as a waiver of such provision or right. SECTION 19.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement shall be cumulative and in addition to other remedies provided under this Agreement or by law or in equity. SECTION 19.5 SEVERABILITY. If any provision of this Agreement is found contrary to law or unenforceable by any court of law, the remaining provisions shall be severable and enforceable in accordance with their terms, unless such unlawful or unenforceable provision is material to the transactions contemplated hereby, in which case the parties shall negotiate in good faith a substitute provision. SECTION 19.6 BINDING EFFECT. This Agreement shall bind and inure to the benefit of the parties and their successors and assigns. 19 CONTRACT #96-205-026 SECTION 19.7 ASSIGNMENT. Neither party may assign this Agreement or any rights or obligations hereunder without the prior written consent of the other party, which consent shall not be unreasonably withheld or denied; provided, however, that Buyer shall have the right, without consent of Seller, to assign all or any part of this Agreement to any company, controlling, controlled by, or under common control with Buyer. SECTION 19.8 ENTIRE AGREEMENT. This Agreement contains the entire agreement between the parties as to the subject matter hereof, and there are no representations, understandings or agreements, oral or written, which are not included herein. SECTION 19.9 AMENDMENTS. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by both parties hereto. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed as of the date first above written. LOUISVILLE GAS AND ELECTRIC KINDILL MINING, INC. COMPANY By: __________________________ By: ________________________________ E. Wayne Parke, Chris Hermann, Vice President & President General Manager Wholesale Electric Business Date: __________________________ Date: ________________________________ 20 CONTRACT #96-205-026 96-205-026 Page 1 of 2 EXHIBIT A SAMPLE COAL PAYMENT CALCULATIONS Total Evaluated Coal Costs for Contract No. 96-205-026 ------------------------------------------------------------------------- For contracts supplied from multiple "origins", each "origin" will be calculated individually
SECTION I BASE DATA - ---------------------------------------------------------------------- 1) Base F.O.B. price per ton: $15.40 /ton 1a) Tons of coal delivered: ________ tons 2) Guaranteed average heat content: 11,000 B.T.U./LB. 2r) As received monthly avg. heat content: ________ B.T.U./LB. 2a) Energy delivered in M.M.B.T.U.: ________ MMBTU [(Line 1a)*2,000 lb./ton*(Line 2r)]*MMBTU/1,000,000 BTU 2b) Base F.O.B. price per M.M.B.T.U.: $________ /MMBTU {[(Line 1)/(Line 2)]*(1 ton/2,000 lb.)}*1,000,000 BTU/MMBTU {[( )/ton)/( BTU/LB)]*(1 ton/2,000 lb.)}*1,000,000 BTU/MMBTU 3) Guaranteed monthly avg. max sulfur 3,100 LBS./MMBTU 3r) As received monthly avg. sulfur ________ LBS./MMBTU 4) Guaranteed monthly avg. max. ash 9,000 LBS./MMBTU 4r) As received monthly avg. ash ________ LBS./MMBTU 5) Guaranteed monthly avg. max. moisture 13,000 LBS./MMBTU 5r) As received monthly avg. moisture ________ LBS./MMBTU SECTION II DISCOUNTS - ---------------------------------------------------------------------- Assign a (-) to all discounts (round to five (5) decimal places) 6d) B.T.U./LB.: If line 2r is less than 11,000 BTU/lb. {1-[(line 2r)/(line 2)]}*$0.2604/MMBTU {1-[( )/( )]}*$0.2604 = $________ /MMBTU 7d) SULFUR: If line 3r is greater than 3,200 lbs./MMBTU [(line 3r)-(line 3)]*$0.1232/lb sulfur [( )-( )]*$0.1232 = $________ /MMBTU 8d) ASH: If line 4r is greater than 9,500 lbs./MMBTU [(line 4r)-(line 4)]*$0.0083/lb ash [( )-( )]*$0.0083 = $________ /MMBTU 9d) MOISTURE: If line 5r is greater than 14,000 lbs./MMBTU [(line 5r)-(line 5)]*$0.0016/lb moisture [( )-( )]*$0.0016 = $________ /MMBTU
21 Contract #96-205-026 96-205-026 Page 2 of 2 SECTION III TOTAL PRICE ADJUSTMENTS - ---------------------------------------------------------- Determine total Discounts as follows: Assign a (-) to all Discounts and enter number for: Line 6d: $________/MMBTU Line 7d: $________/MMBTU Line 8d: $________/MMBTU Line 9d: $________/MMBTU 10) Total Discounts (-): Algebraic sum of above: $________/MMBTU 11) Total evaluated coal price = (line 2b) + (line 10) $________/MMBTU + $________/MMBTU = $________ 12) Total discount price adjustment for Energy delivered: (line 2a) * (line 10) (-) ________ MMBTU * $________/MMBTU = $________ 13) Total base cost of coal (line 2a) * (line 2b) ________ MMBTU * $________/MMBTU = $________ 14) Total coal payment for month (line 12) + (line 13) $________ + $________ = $________
22 EX-10.47 6 EXHIBIT 10.47 EXHIBIT 10.47 October 31, 1996 VIA FACSIMILE: (812/421-0173) AND OVERNIGHT MAIL Royce K. Traylor Sales Manager Kindill Mining, Inc. 101 Court Street, Suite 106 Evansville, Indiana 47708 RE: LG&E EXERCISE OF OPTION Dear Royce: This letter is formal notice that Louisville Gas and Electric Company ("LG&E") is exercising its option under Section 3.2 of the Spot Coal Supply Agreement dated June 1, 1996 between LG&E and Kindill Mining, Inc. to extend the term of the Agreement through December 31, 1997. LG&E hereby designates 750,000 tons as the quantity to be delivered during 1997. LG&E will submit a delivery schedule. Please let me know if you have any questions or comments. Sincerely, Greg P. Cantrell, Director Fuels Procurement and Delivery /LFB EX-10.59 7 EXHIBIT 10.59 EXHIBIT 10.59 AMENDMENT NO. 1 TO CREDIT AGREEMENT This Amendment No. 1 to Credit Agreement ("AMENDMENT NO. 1") is dated as of November 5, 1996, and is by and among LOUISVILLE GAS AND ELECTRIC COMPANY, (the "BORROWER"), the banks set forth herein (collectively, the "BANKS"), and PNC BANK, KENTUCKY, INC. as agent for the Banks (the "AGENT"). WHEREAS, the Borrower, the Banks set forth therein and the Agent are parties to that certain Credit Agreement dated as of December 18, 1995 (the "CREDIT AGREEMENT"); WHEREAS, capitalized terms used herein and not otherwise defined herein shall have the same meanings given to them in the Credit Agreement; and WHEREAS, simultaneously with the execution and delivery of this Amendment No. 1, Bank of Louisville and Trust Co., as assignor ("ASSIGNOR"), and PNC Bank, Kentucky, Inc., as assignee ("ASSIGNEE"), are entering into an Assignment and Assumption Agreement pursuant to which Assignor is assigning all of its right, title and interest in the Commitments, the Notes and the Loan Documents to Assignee. WHEREAS, Union Bank of Switzerland ("UBS") and The First National Bank of Chicago ("FIRST CHICAGO"), by executing this Amendment No. 1, are joining the Credit Agreement as Banks with the respective Commitments set forth on Schedule 1.01(B) hereto. WHEREAS, the Borrower, the Banks and the Agent wish to amend the Credit Agreement as set forth herein. NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the parties hereto, intending to be legally bound, agree as follows: 1. The first recital clause of the Credit Agreement is hereby amended by deleting the number "$160,000,000" in the third line thereof and inserting in lieu thereof "$200,000,000." 2. Section 1.1 of the Credit Agreement is hereby amended by deleting therefrom the definitions of "EXPIRATION DATE," "FOURTH-LEVEL DEBT RATING," "SECOND-LEVEL DEBT RATING" and "THIRD-LEVEL DEBT RATING" and inserting in lieu thereof the following: "EXPIRATION DATE" shall mean, with respect to the Commitments, November 5, 2001. "FOURTH-LEVEL DEBT RATING" shall mean a Borrower Debt Rating of BBB+ if the rating is provided by Standard & Poor's or equal to Baa1 if the rating is provided by Moody's. "SECOND-LEVEL DEBT RATING" shall mean a Borrower Debt Rating equal to or better than A but less than AA- if the rating is provided by Standard & Poor's or equal to or better than A2 but less than Aa3 if the rating is provided by Moody's. "THIRD-LEVEL DEBT RATING" shall mean a Borrower Debt Rating equal to A- if the rating is provided by Standard & Poor's or equal to A3 if the rating is provided by Moody's. 3. Section 1.1 of the Credit Agreement is hereby amended by inserting a new definition of "Fifth-Level Debt Rating" as follows: "FIFTH-LEVEL DEBT RATING" shall mean a Borrower Debt Rating of BBB or lower if the rating is provided by Standard & Poor's or Baa2 or lower if the rating is provided by Moody's. 4. Section 2.03 of the Credit Agreement is hereby amended by deleting the chart setting forth the Borrower Debt Rating and Facility Fee Rate at the end of the first sentence thereof in its entirety and inserting in lieu thereof the following: Borrower Debt Rating Facility Fee Rate -------------------- ----------------- First-Level Debt Rating .06% Second-Level Debt Rating .075% Third-Level Debt Rating .09% Fourth-Level Debt Rating .10% Fifth-Level Debt Rating .15% 5. Section 4.01(a)(ii) of the Credit Agreement is hereby amended by deleting the chart setting forth the Borrower Debt Rating and the Euro-Rate Spread at the end of the first sentence thereof in its entirety and inserting in lieu thereof the following: Borrower Debt Rating Euro-Rate Spread -------------------- ---------------- First-Level Debt Rating .115% Second-Level Debt Rating .15% Third-Level Debt Rating .16% Fourth-Level Debt Rating .20% Fifth-Level Debt Rating .225% 6. Section 8.02(c) of the Credit Agreement is hereby amended by inserting immediately preceding the parenthetical in the third line thereof the following words "any of its properties or assets, tangible or intangible." 2 7. Schedule 1.01(B) of the Credit Agreement is hereby deleted in its entirety and Schedule 1.01(B) attached hereto is inserted in lieu thereof. 8. Exhibit 1.01(B) to the Credit Agreement is hereby deleted in its entirety and Exhibit 1.01(B) attached hereto is hereby inserted in lieu thereof. 9. Exhibit 1.01(G)(2) of the Credit Agreement is hereby deleted in its entirety and Exhibit 1.01(G)(2) attached hereto is inserted in lieu thereof. 10. This Amendment No. 1 shall become effective on the first date on which the following conditions have been satisfied: (a) The Agent on behalf of each Bank shall have received replacement Bid Loan Notes and Revolving Credit Notes reflecting the changes in Schedule 1.01(B). (b) The Agent on behalf of the Banks shall have received a certificate signed by the Secretary or Assistant Secretary of the Borrower certifying as to all action taken by the Borrower to authorize the execution, delivery and performance of this Amendment No. 1 by the Borrower and attaching thereto such resolutions. (c) The Agent shall have received a written opinion from in-house counsel for the Borrower, addressed to the Agent for the benefit of the Banks, opining as to such matters with respect to the transactions contemplated herein as the Agent may reasonably request, in form and substance satisfactory to the Agent and Buchanan Ingersoll Professional Corporation, as special counsel for the Agent and the Banks. 11. The Borrower hereby represents to the Agent and the Banks that: except as disclosed on Schedule 7.02 (as previously delivered to the Agent and the Banks and accepted by the Required Banks), the representations and warranties of the Borrower contained in Article VI of the Credit Agreement remain true and accurate on and as of the date hereof (except for representations and warranties which relate solely to an earlier date or time, which representations and warranties were true and correct on and as of the specific dates or times referred to therein); the Borrower has performed and is in compliance with all covenants contained in Article VIII or elsewhere in the Credit Agreement; no Event of Default or Potential Default has occurred and is continuing. 12. The Borrower hereby agrees to reimburse the Agent on demand for all costs, expenses and disbursements relating to this Amendment No. 1 which are payable by the Borrower as provided in Sections 10.05 and 11.03 of the Credit Agreement. 13. The Borrower and the Banks intend and agree that, except as provided herein, the Credit Agreement shall remain in full force and effect without modification. 3 14. This Amendment No. 1 shall be governed by and construed and enforced in accordance with the internal laws of the Commonwealth of Kentucky without reference to its principles of conflicts of law. 15. Each of UBS and First Chicago (i) confirms that it has received a copy of the Credit Agreement, together with copies of the financial statements (if any) referred to in Sections 6.01(i), 8.03(a) and 8.03(b) of the Credit Agreement and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into the Credit Agreement; (ii) agrees that it will, independently and without reliance upon the Agent or any other Bank, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement; (iii) appoints and authorizes the Agent to take such actions on its behalf and to exercise such powers under the Loan Documents as are delegated to the Agent by the terms thereof; (iv) agrees that it will become a party to and be bound by the Credit Agreement, as amended by Amendment No. 1, on the date hereof (including without limitation the provisions of Section 11.11) as if it were an original Bank thereunder and will have the rights and obligations of a Bank thereunder and will perform in accordance with their terms all of the obligations which by the terms of the Credit Agreement are required to be performed by it as a Bank; and (v) has previously provided the Agent its address for notices. [SIGNATURE PAGES FOLLOW] 4 [SIGNATURE PAGE 1 OF 3 TO AMENDMENT NO. 1 TO CREDIT AGREEMENT] IN WITNESS WHEREOF, the parties hereto by their officers thereunto duly authorized, have executed this Amendment No. 1 to Credit Agreement as of the date first above written. LOUISVILLE GAS AND ELECTRIC COMPANY By: _______________________________________ Title: ____________________________________ PNC BANK, KENTUCKY, INC., individually and as Agent By: _______________________________________ Title: ____________________________________ BANK OF MONTREAL, individually and as Co- Agent By: _______________________________________ Title: ____________________________________ CHASE MANHATTAN BANK, N.A. By: _______________________________________ Title: ____________________________________ 5 [SIGNATURE PAGE 2 OF 3 TO AMENDMENT NO. 1 TO CREDIT AGREEMENT] THE BANK OF NEW YORK By: _______________________________________ Title: ____________________________________ CITIBANK, N.A. By: _______________________________________ Title: ____________________________________ NATIONAL CITY BANK, KENTUCKY By: _______________________________________ Title: ____________________________________ BANK OF LOUISVILLE AND TRUST CO. By: _______________________________________ Title: ____________________________________ BANK ONE, KENTUCKY, N.A. By: _______________________________________ Title: ____________________________________ 6 [SIGNATURE PAGE 3 OF 3 TO AMENDMENT NO. 1 TO CREDIT AGREEMENT] FIFTH THIRD BANK OF KENTUCKY, INC. By: _______________________________________ Title: ____________________________________ UNION BANK OF SWITZERLAND By: _______________________________________ Title: ____________________________________ THE FIRST NATIONAL BANK OF CHICAGO By: _______________________________________ Title: ____________________________________ 7 SCHEDULE 1.01(B) Ratable Bank Commitment Share ---- ---------- ----- PNC Bank, Kentucky, Inc. $ 42,500,000 21.25% Bank of Montreal $ 26,250,000 13.125% Chase Manhattan Bank, N.A. $ 26,250,000 13.125% The Bank of New York $ 21,000,000 10.5% Citibank, N.A. $ 15,750,000 7.875% National City Bank, Kentucky $ 15,750,000 7.875% Bank One, Kentucky, N.A. $ 10,500,000 5.25% Fifth Third Bank of Kentucky, Inc. $ 10,500,000 5.25% Union Bank of Switzerland $ 15,750,000 7.875% The First National Bank of Chicago $ 15,750,000 7.875% ------------ ----- Total $200,000,000 100.0% EXHIBIT 1.01(B) FORM OF BID LOAN NOTE $200,000,000 Louisville, Kentucky ________________, 1996 FOR VALUE RECEIVED, the undersigned, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation (herein called the "BORROWER"), hereby promises to pay to the order of ____________________ (the "BANK") the lesser of (i) the principal sum of Two Hundred Million U.S. Dollars (U.S. $200,000,000), or (ii) the aggregate unpaid principal balance of all Bid Loans made by the Bank to the Borrower pursuant to Sections 3.01 and 3.02 of the Credit Agreement dated as of December 18, 1995 among the Borrower, PNC BANK, KENTUCKY, INC., as agent ("AGENT"), BANK OF MONTREAL, as Co-Agent, the Bank, and the other banks party thereto (as amended, restated, supplemented or modified from time to time, the "CREDIT AGREEMENT"), whichever is less, payable on the Expiration Date or at such other times specified in the Credit Agreement. The Borrower shall pay interest on the unpaid principal balance hereof from time to time outstanding from the date hereof at the rate or rates per annum specified by the Borrower pursuant to Sections 3.01 and 3.02 of, or as otherwise provided in, the Credit Agreement. To the extent permitted by Law, upon the declaration of an Event of Default by the Agent, and until such time as such Event of Default shall have been cured or waived, the Borrower shall pay interest on the entire principal amount of the then outstanding Bid Loans evidenced by this Bid Loan Note at a rate per annum equal to two hundred basis points (2% per annum) above the rate of interest otherwise applicable with respect to such Bid Loans. Such interest rate will accrue before and after any judgment has been entered. Subject to the provisions of the Credit Agreement, interest on this Note will be payable at the times specified in Section 5.03 of the Credit Agreement or as otherwise provided therein. If any payment or action to be made or taken hereunder shall be stated to be or become due on a day which is not a Business Day, such payment or action shall be made or taken on the next following Business Day and such extension of time shall be included in computing interest or fees, if any, in connection with such payment or action. Subject to the provisions of the Credit Agreement, payments of both principal and interest shall be made without setoff, counterclaim or other deduction of any nature at the office of the Agent located at 500 W. Jefferson Street, Louisville, Kentucky 40202, in lawful money of the United States of America in immediately available funds. This Note is a Bid Loan Note referred to in, and is entitled to the benefits of, the Credit Agreement and other Loan Documents, including the representations, warranties, covenants, conditions or Liens contained or granted therein. The Credit Agreement among other things contains provisions for acceleration of the maturity hereof upon the happening of certain stated events and also for prepayment, in certain circumstances, on account of principal hereof prior to maturity upon the terms and conditions therein specified. All capitalized terms used herein shall, unless otherwise defined herein, have the same meanings given to such terms in the Credit Agreement. Except as otherwise provided in the Credit Agreement, the Borrower waives presentment, demand, notice, protest and all other demands and notices in connection with the delivery, acceptance, performance, default or enforcement of this Note and the Credit Agreement. This Note shall bind the Borrower and its successors and assigns, and the benefits hereof shall inure to the benefit of the Bank and its successors and assigns. All references herein to the "Borrower" and the "Bank" shall be deemed to apply to the Borrower and the Bank, respectively, and their respective successors and assigns. This Note and any other documents delivered in connection herewith and the rights and obligations of the parties hereto and thereto shall for all purposes be governed by and construed and enforced in accordance with the internal laws of the Commonwealth of Kentucky without giving effect to its conflicts of law principles. IN WITNESS WHEREOF, the undersigned has executed this Note by its duly authorized officers with the intention that it constitute a sealed instrument. ATTEST: LOUISVILLE GAS AND ELECTRIC COMPANY __________________________________ By: ________________________________ Title: ___________________________ Name: ______________________________ Title: _____________________________ [Seal] 2 EXHIBIT 1.01(G)(2) FORM OF GUARANTY AND SURETYSHIP AGREEMENT This Agreement (the "Agreement") dated as of _______________, 199__, is made and given by the undersigned signatories, each a Subsidiary of Louisville Gas and Electric Company, a Kentucky corporation ("Borrower"), identified in Schedule 1 attached hereto and made a part hereof (each a "Guarantor" and collectively, the "Guarantors"), in favor of the Banks (as defined in that certain Credit Agreement dated December 18, 1995 among PNC Bank, Kentucky, Inc., a Kentucky banking corporation, as agent (the "Agent"), the Banks party thereto and the Borrower, as it may from time to time be amended, restated, modified or supplemented, the "Credit Agreement"). W I T N E S S E T H: WHEREAS, Borrower has entered into the Credit Agreement with the Agent and the Banks; and WHEREAS, this Agreement is made by the Guarantors among other things to comply with the requirements of the Credit Agreement; and WHEREAS, the respective businesses and investments of the Guarantors are interdependent and loans made to the Borrower under the Credit Agreement are with the expectation that the profits and other opportunities from such loans will directly or indirectly inure to the benefit of each Guarantor and to all of them taken as an affiliated group. NOW, THEREFORE, in consideration of the premises, and intending to be legally bound, the Guarantors hereby agree as follows: ARTICLE I DEFINITIONS 1.01 Definitions. Capitalized terms used herein and not otherwise defined herein shall have such meanings as given to them in the Credit Agreement. In addition to the other terms defined elsewhere in this Agreement, the following terms shall have the following meanings: "Guaranteed Obligations" shall mean all obligations from time to time of the Borrower to the Agent and the Banks under or in connection with the Credit Agreement, the Notes issued in connection therewith in the maximum aggregate principal amount of $200,000,000 or any other Loan Document or which arise in any other manner, whether for principal, interest, fees, indemnities, expenses or otherwise, and all refinancings or refundings thereof, whether such obligations are direct or indirect, otherwise secured or unsecured, joint or several, absolute or contingent, due or to become due, whether for payment or performance, now existing or hereafter arising (specifically including but not limited to Obligations arising or accruing after the commencement of any bankruptcy, insolvency, reorganization or similar proceeding with respect to the Borrower or any other individual or entity (a "Person") including any Guarantor or which would have arisen or accrued but for the commencement of such proceeding, even if the claim for such Obligation is not enforceable or allowable in such proceeding). Without limitation of the foregoing, such obligations include all obligations arising from any extensions of credit under or in connection with the Loan Documents from time to time, regardless of whether any such extensions of credit are in excess of the amount committed under or contemplated by the Loan Documents or are made in circumstances in which any condition to extension of credit is not satisfied. Without limitation of the foregoing, the Agent and the Banks (or any successive assignee or transferee) from time to time may, subject to the provisions of the Credit Agreement, assign or otherwise transfer all of their respective rights and obligations under the Loan Documents (including, without limitation, all of any commitment to extend credit), or any other Guaranteed Obligations, to any other Person, and such Guaranteed Obligations (including, without limitation, any Guaranteed Obligations resulting from extension of credit by such other Person under or in connection with the Loan Documents) assigned or otherwise transferred in accordance with the terms of the Credit Agreement shall be and remain Guaranteed Obligations entitled to the benefit of this Agreement. ARTICLE II GUARANTY AND SURETYSHIP 2.01 Guaranty and Suretyship. The Guarantors jointly and severally hereby absolutely, unconditionally and irrevocably guarantee and become surety for the full and punctual payment and performance of the Guaranteed Obligations as and when such payment or performance shall become due (at scheduled maturity, by acceleration or otherwise) in accordance with the terms of the Loan Documents. This Agreement is an agreement of suretyship as well as of guaranty, is a guarantee of payment and performance and not merely of collectibility, and is in no way conditioned upon any attempt to collect from or proceed against the Borrower or any other Person or any other event or circumstance. The obligations of the Guarantors under this Agreement are direct and primary obligations of each Guarantor and are independent of the Guaranteed Obligations, and a separate action or actions may be brought against any one or more of the Guarantors regardless of whether action is brought against the Borrower, any other Guarantor or any other Person or whether the Borrower, any other Guarantor or any other Person is joined in any such action or actions. 2.02 Obligations Absolute. The Guarantors agree that the Guaranteed Obligations will be paid and performed strictly in accordance with the terms of the Loan Documents, regardless of any law, regulation or order now or hereafter in effect in any jurisdiction affecting the Guaranteed Obligations, any of the terms of the Loan Documents or the rights of the Agent and the Banks or any other Person with respect thereto. The obligations of the Guarantors under this Agreement shall be absolute, unconditional and irrevocable, irrespective of any of the following: 2 (a) Any lack of genuineness, legality, validity, enforceability or allowability (in a bankruptcy, insolvency, reorganization or similar proceeding, or otherwise), or any avoidance or subordination, in whole or in part, of any Loan Document or any of the Guaranteed Obligations. (b) Any increase, decrease or change in the amount, nature, type or purpose of any of the Guaranteed Obligations (whether or not contemplated by the Loan Documents as presently constituted); any change in the time, manner, method or place of payment or performance of, or in any other term of, any of the Guaranteed Obligations; any execution or delivery of any additional Loan Documents; or any amendment, modification or supplement to, or refinancing or refunding of, any Loan Document or any of the Guaranteed Obligations. (c) Any failure to assert any breach of or default under any Loan Document or any of the Guaranteed Obligations; any extensions of credit in excess of the amount committed under or contemplated by the Loan Documents, or in circumstances in which any condition to such extensions of credit has not been satisfied; any other exercise or non-exercise, or any other failure, omission, breach, default, delay or wrongful action in connection with any exercise or non-exercise, of any right or remedy against the Borrower or any other Person under or in connection with any Loan Document or any of the Guaranteed Obligations; any refusal of payment or performance of any of the Guaranteed Obligations, whether or not with any reservation of rights against any Guarantor; or any application of collections (including but not limited to collections resulting from realization upon any direct or indirect security for the Guaranteed Obligations) to other obligations, if any, not entitled to the benefits of this Agreement, in preference to Guaranteed Obligations entitled to the benefits of this Agreement, or if any collections are applied to Guaranteed Obligations, any application to particular Guaranteed Obligations. (d) Any taking, exchange, amendment, modification, supplement, termination, subordination, release, loss or impairment of, OR any failure to protect, perfect, or preserve the value of, OR any enforcement of, realization upon, or exercise of rights, or remedies under or in connection with, OR any failure, omission, breach, default, delay or wrongful action by the Agent and the Banks, or any of them, or any other Person in connection with the enforcement of, realization upon, or exercise of rights or remedies under or in connection with, OR any other action or inaction by the Agent and the Banks, or any of them, or any other Person in respect of, any direct or indirect security for any of the Guaranteed Obligations. As used in this Agreement, "direct or indirect security" for the Guaranteed Obligations, and similar phrases, includes but is not limited to any collateral security, guaranty, suretyship, letter of credit, capital maintenance agreement, put option, subordination agreement or other right or arrangement of any nature providing direct or indirect assurance of payment or performance of any of the Guaranteed Obligations, made by or on behalf of any Person. 3 (e) Any merger, consolidation, liquidation, dissolution, winding-up, charter revocation or forfeiture, or other change in, restructuring or termination of the corporate structure or existence of, the Borrower or any other Person; any bankruptcy, insolvency, reorganization or similar proceeding with respect to the Borrower or any other Person; or any action taken or election made by the Agent and the Banks, or any of them (including but not limited to any election under Section 1111(b)(2) of the United States Bankruptcy Code), the Borrower or any other Person in connection with any such proceeding. (f) Any defense, setoff or counterclaim (excluding only the defense of full, strict and indefeasible payment and performance), which may at any time be available to or be asserted by the Borrower, any Guarantor or any other Person with respect to any Loan Document or any of the Guaranteed Obligations; or any discharge by operation of law or release of the Borrower, any Guarantor or any other Person from the performance or observance of any Loan Document or any of the Guaranteed Obligations. (g) Any other event or circumstance, whether similar or dissimilar to the foregoing, and whether known or unknown, which might otherwise constitute a defense available to, or limit the liability of or discharge, any Guarantor, a guarantor or a surety, excepting only full, strict and indefeasible payment and performance of the Guaranteed Obligations in full. 2.03. Waivers, etc. The Guarantors hereby waive any defense to or limitation on their obligations under this Agreement arising out of or based on any event or circumstance referred to in Section 2.02 hereof. Without limitation and to the full extent permitted by applicable law, the Guarantors waive each of the following: (a) All notices, disclosures and demand of any nature which otherwise might be required from time to time to preserve intact any rights against any Guarantor, including without limitation the following: any notice of any event or circumstance described in Section 2.02 hereof; any notice required by any law, regulation or order now or hereafter in effect in any jurisdiction; any presentment, notice of nonpayment, nonperformance, dishonor, or protest under any Loan Document or any of the Guaranteed Obligations; any notice of the incurrence of any Guaranteed Obligation; any notice of any default or any failure on the part of the Borrower or any other Person to comply with any Loan Document or any of the Guaranteed Obligations or any direct or indirect security for any of the Guaranteed Obligations; and any notice of any information pertaining to the business, operations, condition (financial or otherwise) or prospects of the Borrower or any other Person. (b) Any right to any marshalling of assets, to the filing of any claim against the Borrower or any other Person in the event of any bankruptcy, insolvency, reorganization or similar proceeding, or to the exercise against the Borrower or 4 any other Person of any other right or remedy under or in connection with any Loan Document or any of the Guaranteed Obligations or any direct or indirect security for any of the Guaranteed Obligations; any requirement of promptness or diligence on the part of the Agent and the Banks, or any of them, or any other Person; any requirement to exhaust any remedies under or in connection with, or to mitigate the damages resulting from default under, any Loan Document or any of the Guaranteed Obligations or any direct or indirect security for any of the Guaranteed Obligations; any benefit of any statute of limitations; and any requirement of acceptance of this Agreement, and any requirement that any Guarantor receive notice of such acceptance. (c) Any defense or other right arising by reason of any law now or hereafter in effect in any jurisdiction pertaining to election of remedies (including but not limited to anti-deficiency laws, "one action" laws or the like), or by reason of any election of remedies or other action or inaction by the Agent and the Banks, or any of them (including but not limited to commencement or completion of any judicial proceeding or nonjudicial sale or other action in respect of collateral security for any of the Guaranteed Obligations), which results in denial or impairment of the right of the Agent and the Banks, or any of them, to seek a deficiency against the Borrower or any other Person or which otherwise discharges or impairs any of the Guaranteed Obligations. (d) Notwithstanding any payment or payments made by each Guarantor hereunder, or any set-off or application of funds of such Guarantor by the Agent or any Bank, such Guarantor shall not be entitled to be subrogated to any of the rights of the Agent or any Bank against the Borrower or against any collateral security or guarantee or right of offset held by the Agent or any Bank for the payment of the Guaranteed Obligations, nor shall such Guarantor seek any reimbursement from the Borrower in respect of payments made by such Guarantor hereunder, until all amounts owing to the Agent and the Banks by the Borrower on account of the Guaranteed Obligations are paid in full and the Commitments are terminated. If any amount shall be paid to any Guarantor on account of such subrogation rights at any time when all of the Obligations shall not have been paid in full, such amount shall be held by such Guarantor in trust for the Agent and the Banks, segregated from other funds of such Guarantor, and shall, forthwith upon receipt by such Guarantor, be turned over to the Agent in the exact form received by such Guarantor (duly endorsed by such Guarantor to the Agent, if required), to be applied against the Guaranteed Obligations, whether matured or unmatured, in such order as the Agent may determine. 2.04. Reinstatement. This Agreement shall continue to be effective, or be automatically reinstated, as the case may be, if at any time payment of any of the Guaranteed Obligations is avoided, rescinded or must otherwise be returned by the Agent and the Banks, or any of them, for any reason (including, without limitation, by reason of such payment being a 5 preference, fraudulent transfer or fraudulent conveyance), all as though such payment had not been made. 2.05. No Stay. Without limitation of any other provision of this Agreement, if any declaration of default or acceleration or other exercise or condition to exercise of rights or remedies under or with respect to any Guaranteed Obligation shall at any time be stayed, enjoined or prevented for any reason (including but not limited to stay or injunction resulting from the pendency against the Borrower or any other Person of a bankruptcy, insolvency, reorganization or similar proceeding), the Guarantors agree that, for the purposes of this Agreement and their obligations hereunder, the Guaranteed Obligations shall be deemed to have been declared in default or accelerated, and such other exercise or conditions to exercise shall be deemed to have been taken or met. 2.06. Payments. All payments to be made by any Guarantor pursuant to this Agreement shall be made without setoff, counterclaim, or other deduction of any nature (other than deductions for the withholding of United States federal income tax which is due and payable by a Bank in connection with the income it receives under the Loan Documents, provided that the Agent has elected not to make such withholdings). 2.07. Continuing Guaranty. This Agreement is a continuing agreement and shall continue in full force and effect (notwithstanding that no Guaranteed Obligations may be outstanding from time to time, or any other event or circumstance) until all Guaranteed Obligations and all other amounts payable under this Agreement have been paid and performed in full, and all commitments to extend credit under the Loan Documents have terminated, subject in any event to reinstatement in accordance with Section 2.04 hereof. Any purported termination, revocation or discharge of this Agreement (other than in accordance with the preceding sentence) shall be void and of no effect. For purposes of this Agreement the Guaranteed Obligations shall not be deemed to have been paid in full until the Agent and the Banks shall have indefeasibly received payment of the Guaranteed Obligations in full and in cash and all commitments to extend credit under the Loan Documents have terminated. Anything contained in this Agreement to the contrary notwithstanding, this Agreement shall terminate on November 5, 2001 except that such termination shall not effect the liability of Guarantors with respect to (i) obligations created or incurred prior to such date, or (ii) extensions or renewals of, interest accruing on, or fees, costs or expenses, including reasonable attorney's fees, incurred with respect to, such obligations on or after such date. ARTICLE III REPRESENTATIONS AND WARRANTIES Each Guarantor hereby represents and warrants to the Agent and the Banks with respect to itself as follows: 3.01. No Conditions Precedent. There are no conditions precedent to the effectiveness of this Guaranty that have not been satisfied or waived. 6 3.02. No Reliance. Each Guarantor has, independently and without reliance upon the Agent and the Banks, or any of them, and based upon such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. 3.03. Representations and Warranties Remade at Each Extension of Credit. Each request (including any deemed request) by the Borrower for any extension of credit under the Credit Agreement shall be deemed to constitute a representation and warranty by each Guarantor to the Agent and the Banks that the representations and warranties made by each Guarantor in this Agreement are true and correct on and as of the date of such request with the same effect as though made on and as of such date. Failure by the Agent and the Banks to receive notice from any Guarantor to the contrary before the Agent and the Banks make any extension of credit under any Loan Document shall constitute a further representation and warranty by such Guarantor to the Agent and the Banks that the representations and warranties made by the Borrower are true and correct on and as of the date of such extension of credit with the same effect as though made on and as of such date. ARTICLE IV MISCELLANEOUS 4.01. Amendments, etc. No amendment to or waiver of any provision of this Agreement, and no consent to any departure by any Guarantor herefrom, shall in any event be effective unless in a writing manually signed by or on behalf of the Agent and, in the case of an amendment, each of the Guarantors. Any such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given. 4.02. No Implied Waiver; Remedies Cumulative. No delay or failure of the Agent and the Banks, or any of them, in exercising any right or remedy under this Agreement shall operate as a waiver thereof; nor shall any single or partial exercise of any such right or remedy preclude any other or further exercise thereof or the exercise of any other right or remedy. The rights and remedies of the Agent and the Banks under this Agreement are cumulative and not exclusive of any other rights or remedies available hereunder, under any other agreement or instrument, by law, or otherwise. 4.03. Notices. Each Guarantor agrees that all notices, statements, requests, demands and other communications under this Agreement shall be given to such Guarantor at the address set forth on the signature page hereof in the manner provided in Section 11.06 of the Credit Agreement. The Agent and the Banks may rely on any notice (whether or not made in a manner contemplated by this Agreement) purportedly made by or on behalf of a Guarantor, and the Agent and the Banks shall have no duty to verify the identity or authority of the Person giving such notice. 4.04. Expenses. Each Guarantor unconditionally agrees to pay all costs and expenses, including reasonable attorney's fees, incurred by the Agent and any of the Banks in enforcing this Agreement against any Guarantor. 7 4.05. Prior Understandings. This Agreement constitutes the entire agreement of the parties hereto with respect to the subject matter hereof and supersedes all prior and contemporaneous understandings and agreements. 4.06. Survival. All representations and warranties of the Guarantors contained in or made in connection with this Agreement shall survive, and shall not be waived by, the execution and delivery of this Agreement, any investigation by or knowledge of the Agent and the Banks, or any of them, any extension of credit, or any other event or circumstance whatsoever. 4.07. Counterparts. This Agreement may be executed in any number of counterparts, each of which, when so executed, shall be deemed an original, but all such counterparts shall constitute but one and the same instrument. 4.08. Setoff. In the event that at any time any obligation of the Guarantors now or hereafter existing under this Agreement shall have become due and payable, the Agent and the Banks, or any of them, shall have the right from time to time, without notice to any Guarantor, to set off against and apply to such due and payable amount any obligation of any nature of the Agent and the Banks to any Guarantor, including but not limited to all deposits (whether time or demand, general or special, provisionally credited or finally credited, however evidenced) now or hereafter maintained by any Guarantor with the Agent or the Banks. Such right shall be absolute and unconditional in all circumstances and, without limitation, shall exist whether or not the Agent and/or the Banks, or any of them, shall have given any notice or made any demand under this Agreement or under such obligation to such Guarantor, whether such obligation of such Guarantor is absolute or contingent, matured or unmatured (it being agreed that the Agent and the Banks, or any of them, may deem such obligation to be then due and payable at the time of such setoff), and regardless of the existence or adequacy of any guaranty or other direct or indirect security, right or remedy available to the Agent and the Banks. The rights of the Agent and the Banks under this Section are in addition to such other rights and remedies (including, without limitation, other rights of setoff and banker's lien) which the Agent and the Banks, or any of them, may have, and nothing in this Agreement or in any other Loan Document shall be deemed a waiver of or restriction on the right of setoff or banker's lien of the Agent and the Banks, or any of them. The Guarantors hereby agree that, to the fullest extent permitted by law, any affiliate of the Agent and the Banks, or any of them, and any holder of a participation in any obligation of any Guarantor under this Agreement, shall have the same rights of setoff as the Agent and the Banks as provided in this Section 4.08 (regardless of whether such affiliate or participant otherwise would be deemed a creditor of any Guarantor). 4.09. Construction. The section and other headings contained in this Agreement are for reference purposes only and shall not affect interpretation of this Agreement in any respect. This Agreement has been fully negotiated between the applicable parties, each party having the benefit of legal counsel, and accordingly neither any doctrine of construction of guaranties or suretyships in favor of the guarantor or surety, nor any doctrine of construction of ambiguities in agreements or instruments against the party controlling the drafting thereof, shall apply to this Agreement. 8 4.10. Successors and Assigns. This Agreement shall be binding upon each Guarantor, its successors and assigns, and shall inure to the benefit of and be enforceable by the Agent and the Banks, or any of them, and their successors and permitted assigns (as provided in the Credit Agreement). Without limitation of the foregoing, the Agent and the Banks, or any of them (and any successive assignee or transferee), from time to time may, subject to the applicable provisions of the Credit Agreement, assign or otherwise transfer all or any portion of its rights or obligations under the Loan Documents (including, without limitation, all or any portion of any commitment to extend credit), or any other Guaranteed Obligations, to any other Person and such Guaranteed Obligations (including, without limitation, any Guaranteed Obligations resulting from extension of credit by such other Person under or in connection with the Loan Documents) assigned or otherwise transferred in accordance with the terms of the Credit Agreement shall be and remain Guaranteed Obligations entitled to the benefit of this Agreement, and to the extent of its interest in such Guaranteed Obligations such other Person shall be vested with all the benefits in respect thereof granted to the Agent and the Banks in this Agreement or otherwise. 4.11. Governing Law; Submission to Jurisdiction; Waiver of Jury Trial. (a) Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY, CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE COMMONWEALTH OF KENTUCKY, WITHOUT REGARD TO CONFLICT OF LAWS PRINCIPLES. (b) Certain Waivers. EACH GUARANTOR HEREBY IRREVOCABLY: (i) CONSENTS TO THE NONEXCLUSIVE JURISDICTION OF THE CIRCUIT COURT OF JEFFERSON COUNTY, KENTUCKY AND THE UNITED STATES DISTRICT COURT FOR THE WESTERN DISTRICT OF KENTUCKY, AND WAIVES PERSONAL SERVICE OF ANY AND ALL PROCESS UPON IT AND CONSENTS THAT ALL SUCH SERVICE OF PROCESS BE MADE BY CERTIFIED OR REGISTERED MAIL DIRECTED TO SUCH GUARANTOR AT THE ADDRESS PROVIDED FOR IN SECTION 4.03 HEREOF AND SERVICE SO MADE SHALL BE DEEMED TO BE COMPLETED UPON ACTUAL RECEIPT THEREOF; (ii) WAIVES ANY OBJECTION TO JURISDICTION AND VENUE OF ANY ACTION INSTITUTED AGAINST IT AS PROVIDED HEREIN AND AGREES NOT TO ASSERT ANY DEFENSE BASED ON LACK OF JURISDICTION OR VENUE OR BASED ON INCONVENIENT FORUM; AND (iii) WAIVES TRIAL BY JURY IN ANY ACTION, SUIT, PROCEEDING OR COUNTERCLAIM OF ANY KIND ARISING OUT OF OR RELATED TO THIS AGREEMENT, THE CREDIT AGREEMENT OR 9 ANY OTHER LOAN DOCUMENT TO THE FULL EXTENT PERMITTED BY LAW. (c) Limitation of Liability. TO THE FULLEST EXTENT PERMITTED BY LAW, NO CLAIM MAY BE MADE BY ANY GUARANTOR OR ANY OTHER PERSON AGAINST THE AGENT AND THE BANKS, OR ANY OF THEM, OR ANY AFFILIATE, DIRECTOR, OFFICER, EMPLOYEE, ATTORNEY OR AGENT OF THE AGENT AND THE BANKS FOR ANY SPECIAL, INDIRECT, CONSEQUENTIAL OR PUNITIVE DAMAGES IN RESPECT OF ANY CLAIM ARISING FROM OR RELATING TO THIS AGREEMENT OR ANY STATEMENT, COURSE OF CONDUCT, ACT, OMISSION, OR EVENT OCCURRING IN CONNECTION HEREWITH (WHETHER FOR BREACH OF CONTRACT, TORT OR ANY OTHER THEORY OF LIABILITY); AND EACH GUARANTOR HEREBY WAIVES, RELEASES AND AGREES NOT TO SUE UPON ANY CLAIM FOR ANY SUCH DAMAGES, WHETHER OR NOT ACCRUED AND WHETHER OR NOT KNOWN OR SUSPECTED TO EXIST IN ITS FAVOR. 4.12. Severability; Modification to Conform to Law. 10 (a) It is the intention of the parties that this Agreement be enforceable to the fullest extent permissible under applicable law, but that the unenforceability (or modification to conform to such Law) of any provision or provisions hereof shall not render unenforceable, or impair, the remainder hereof. If any provision in this Agreement shall be held invalid or unenforceable in whole or in part in any jurisdiction, this Agreement shall, as to such jurisdiction, be deemed amended to modify or delete, as necessary, the offending provision or provisions and to alter the bounds thereof in order to render it or them valid and enforceable to the maximum extent permitted by applicable Law, without in any manner affecting the validity or enforceability of such provision or provisions in any other jurisdiction or the remaining provisions hereof in any jurisdiction. (b) Without limitation of the preceding subsection (a), to the extent that mandatory applicable law (including but not limited to applicable laws pertaining to fraudulent conveyance or fraudulent transfer) otherwise would render the full amount of any Guarantor's obligations hereunder invalid or unenforceable, such Guarantor's obligations hereunder shall be limited to the maximum amount which does not result in such invalidity or unenforceability. (c) Notwithstanding anything to the contrary in this Section 4.12 or elsewhere in this Agreement, this Agreement shall be presumptively valid and enforceable to its full extent in accordance with its terms, as if this Section 4.12 (and references elsewhere in this Agreement to enforceability to the fullest extent permitted by Law) were not a part of this Agreement, and in any related litigation the burden of proof shall be on the party asserting the invalidity or unenforceability of any provision hereof or asserting any limitation on any Guarantor's obligations hereunder as to each element of such assertion. 4.13. Additional Guarantors. At any time after the initial execution and delivery of this Agreement to the Agent and the Banks, additional Persons may become parties to this Agreement and thereby acquire the duties and rights of being Guarantors hereunder by executing and delivering to the Agent and the Banks a counterpart signature page for attachment hereto. No notice of the addition of any Guarantor shall be required to be given to any pre-existing Guarantor. 4.14. Joint and Several Obligations. The obligations of each Guarantor under this Agreement are joint and several. 4.15 Receipt of Credit Agreement and Other Loan Documents. Each Guarantor hereby acknowledges that it has received a copy of the Credit Agreement and the other Loan Documents and each Guarantor certifies that the representations and warranties made therein with respect to such Guarantor are true and correct. Further, each Guarantor acknowledges and agrees to perform, comply with and be bound by all of the provisions of the Credit Agreement and the other Loan Documents including, without limitation, those covenants contained in Sections 8.01 and 8.02 of the Credit Agreement. 11 [SIGNATURE PAGE FOLLOWS] [SIGNATURE PAGE 1 OF 1 TO THE GUARANTY AND SURETYSHIP AGREEMENT] IN WITNESS WHEREOF, the undersigned have caused this Agreement to be duly executed and delivered as of the date first above written. GUARANTORS: ATTEST: EACH GUARANTOR LISTED ON SCHEDULE 1 By: _______________________________ By: _____________________________________ Address for notices to each Guarantor: _________________________________________ _________________________________________ _________________________________________ Telecopier No. __________________________ Attention: ______________________________ Telephone No. ___________________________ 12 SCHEDULE 1 TO THE GUARANTY AND SURETYSHIP AGREEMENT PNC BANK, KENTUCKY, INC., AS AGENT LOUISVILLE GAS AND ELECTRIC COMPANY, AS BORROWER Subsidiary and State of Formation 13 EX-12 8 EXHIBIT 12 COMP OF RATIO OF EARNINGS TO FIXED CHRG EXHIBIT 12 LOUISVILLE GAS AND ELECTRIC COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Thousands of $)
1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- Earnings: Income before cumulative effect of a change in accounting principle per statements of income ................................ $ 107,941 $ 83,184 $ 61,689 $ 90,535 $ 73,793 Add: Federal income taxes - current ............ 34,019 35,824 30,926 42,091 13,785 State income taxes - current .............. 7,589 8,795 7,726 12,954 3,140 Deferred Federal income taxes - net ....... 19,816 4,261 (950) 4,712 20,441 Deferred State income taxes - net ......... 6,648 2,788 956 226 8,470 Investment tax credit - net ............... (4,406) (4,742) (4,619) (7,821) (5,033) Fixed charges ............................. 42,198 43,550 44,665 49,640 52,196 --------- --------- --------- --------- --------- Earnings ................................. 213,805 173,660 140,393 192,337 166,792 --------- --------- --------- --------- --------- Fixed Charges: Interest Charges per statements of income.. 40,242 41,918 42,856 47,496 49,833 Add: Interest income (1) ...................... 409 -- -- -- 4 One-third of rentals charged to operating expense (2) ................... 1,547 1,632 1,809 2,144 2,359 --------- --------- --------- --------- --------- Fixed charges ......................... $ 42,198 $ 43,550 $ 44,665 $ 49,640 $ 52,196 --------- --------- --------- --------- --------- Ratio of Earnings to Fixed Charges .......... 5.07 3.99 3.14 3.87 3.20 ========= ========= ========= ========= =========
NOTE: (1) Interest income earned on pollution control revenue bond proceeds held and invested by trustees - netted against interest charges above. (2) In the Company's opinion, one-third of rentals represents a reasonable approximation of the interest factor. EX-23 9 EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCTS EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report dated January 29, 1997, included in this Form 10-K, into the Company's previously filed Registration Statement No. 33-13427. Louisville, Kentucky Arthur Andersen LLP March 25, 1997 ---------------------- Arthur Andersen LLP EX-24 10 EXHIBIT 24 POWER OF ATTORNEY Exhibit 24 POWER OF ATTORNEY WHEREAS, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, is to file with the Securities and Exchange Commission, under the provisions of the Securities Act of 1934, as amended, its Annual Report on Form 10-K for the year ended December 31, 1996 (the 1996 Form 10-K); and WHEREAS, each of the undersigned holds the office or offices in LOUISVILLE GAS AND ELECTRIC COMPANY set opposite his name; NOW, THEREFORE, each of the undersigned hereby constitutes and appoints ROGER W. HALE and M. L. FOWLER, and each of them, individually, his attorney, with full power to act for him and in his name, place, and stead, to sign his name in the capacity or capacities set forth below to the 1996 Form 10-K and to any and all amendments to such 1996 Form 10-K and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned have hereunto set their hands and seals this 5th day of March 1997. Roger W. Hale J. David Grissom - --------------------------------- ------------------------------------ Roger W. Hale, Principal J. David Grissom, Director Executive Officer and Director William C. Ballard, Jr. David B. Lewis - --------------------------------- ------------------------------------ William C. Ballard, Jr., Director David B. Lewis, Director Ronald L. Bittner Anne H. McNamara - --------------------------------- ------------------------------------ Ronald L. Bittner, Director Anne H. McNamara, Director Owsley Brown II T. Ballard Morton, Jr. - --------------------------------- ------------------------------------ Owsley Brown II, Director T. Ballard Morton, Jr., Director S. Gordon Dabney Dr. Donald C. Swain - --------------------------------- ------------------------------------ S. Gordon Dabney, Director Dr. Donald C. Swain, Director Gene P. Gardner Charles A. Markel III - --------------------------------- ------------------------------------ Gene P. Gardner, Director Charles A. Markel III, Principal Financial Officer M. L. Fowler - --------------------------------- M. L. Fowler, Principal Accounting Officer STATE OF KENTUCKY ) )ss. COUNTY OF JEFFERSON ) On this 5th day of March 1997, before me, Kathryn M. Carpenter, a Notary Public, State of Kentucky at Large, personally appeared the above named directors and officers of LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, and known to me to be the persons whose names are subscribed to the foregoing instrument, and they severally acknowledged to me that they executed the same as their own free act and deed. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal on the date above set forth. My Commission expires: Kathryn M. Carpenter November 2, 2000 Kathryn M. Carpenter, Notary Public State of Kentucky at Large EX-27 11 EXHIBIT 27
UT 1,000 YEAR DEC-31-1996 JAN-01-1996 DEC-31-1996 PER-BOOK 1,685,222 1,028 260,523 59,939 0 2,006,712 424,334 201 209,222 633,757 46,223 49,105 646,835 0 0 0 0 0 0 0 630,792 2,006,712 821,115 63,259 610,593 673,852 147,263 920 148,183 40,242 107,941 4,568 103,373 75,200 39,771 185,552 0 0
EX-99.01 12 EXHIBIT 99.01 Exhibit 99.01 Louisville Gas and Electric Company Cautionary Factors The Private Securities Litigation Reform Act of 1995 provides a "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been and will be made in written documents and oral presentations of Louisville Gas and Electric Company (the "Company"). Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used in the Company's documents or oral presentations, the words "anticipate", "estimate", "expect", "objective" and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: * Increased competition in the utility industry, including effects of: decreasing margins as a result of competitive pressures; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market; * Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, currency, interest rate and warranty risks; * Risks associated with price risk management strategies intended to mitigate exposure to adverse movement in the prices of electricity and natural gas on both a global and regional basis; * Economic conditions including inflation rates and monetary fluctuations; * Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services; * Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission, state public utility commissions, state entities which regulate natural gas transmission, gathering and processing and similar entities with regulatory oversight; * Availability or cost of capital such as changes in: interest rates, market perceptions of the utility and energy-related industries, the Company or security ratings; * Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints; * Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages; * Rate-setting policies or procedures of regulatory entities, including environmental externalities; * Social attitudes regarding the utility, natural gas and power industries; * Costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including but not limited to those described in Note 13 of the Notes to Financial Statements of the Company's Annual Report on Form 10-K for the year ended December 31, 1996, under the caption Commitments and Contingencies; * Technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets; * Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. -----END PRIVACY-ENHANCED MESSAGE-----