-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, TDskitOYHHnwnyqQtsypyrqCTXSoMjRexkoQgCKiw0PhJCoSgro0CSse/dVfsK+C BcfCpJSdzhQDhmeB8+c+8g== 0000912057-95-001802.txt : 199507120000912057-95-001802.hdr.sgml : 19950711 ACCESSION NUMBER: 0000912057-95-001802 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950328 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-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02893 FILM NUMBER: 95523938 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 2: 220 WEST MAIN STREET CITY: LUUISVILLE STATE: KY ZIP: 40232 10-K 1 FORM 10-K 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 (FEE REQUIRED) For the fiscal year ended DECEMBER 31, 1994 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 7.45% 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. [ ] As of February 28, 1995, the aggregate market value of the registrant's voting stock held by non-affiliates was $34,357,392 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 16, 1995, is incorporated by reference into Part III of this Form 10-K. 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. . . . . . . . . . . . . . . . . . . . . . . . . . 8 Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Environmental Matters. . . . . . . . . . . . . . . . . . . . . 9 Labor Relations. . . . . . . . . . . . . . . . . . . . . . . . 10 Employees. . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . 11 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . 12 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 . . . . . . . . . . . . . . 15 Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . 23 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . 46 PART III Item 10. Directors and Executive Officers of the Registrant (a). . . . . . 47 Item 11. Executive Compensation (a). . . . . . . . . . . . . . . . . . . . 47 Item 12. Security Ownership of Certain Beneficial Owners and Management (a) . . . . . . . . . . . . . . . . . . . . . . 47 Item 13. Certain Relationships and Related Transactions (a). . . . . . . . 47 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . 47 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges . . . . . . 62 Exhibit 23 - Consent of Independent Public Accountants . . . . . . . . . . 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 266,000 customers and electricity to approximately 341,000 customers in Louisville and adjacent areas in Kentucky. The Company's service area covers approximately 700 square miles in 17 counties and has an estimated population of 800,000. Included in this area is the Fort Knox Military Reservation, to which the Company provides both gas and electric service, but which maintains its own distribution systems. The Company also provides gas service in limited additional areas. The Company's coal-fired electric generating plants, which are all equipped with systems to remove sulfur dioxide, produce most of the Company's electricity; the remainder is generated by a hydroelectric power plant and combustion turbines. Underground gas storage fields help the Company provide economical and reliable gas service to customers. In August 1990, the Company and LG&E Energy Corp. (Energy Corp.) implemented a corporate reorganization pursuant to a mandatory share exchange whereby each share of outstanding common stock of the Company was exchanged on a share-for-share basis for the common stock of Energy Corp. The reorganization created a corporate structure that gives the holding company the flexibility to take advantage of opportunities to expand into other businesses while insulating the Company's utility customers and senior security holders from any risks associated with such businesses. The Company's preferred stock and first mortgage bonds were not exchanged and remained securities of the Company. The Company's Trimble County Unit 1 (Trimble County or the Unit), a 495-megawatt, coal-fired electric generating unit, which the Company began constructing in 1979, was placed in commercial operation on December 23, 1990. The Unit has been subject to numerous reviews by the Public Service Commission of Kentucky (Kentucky Commission or Commission). In July 1988, the Kentucky Commission issued an order stating that 25% of the total cost of the Unit would not be allowed for ratemaking purposes. The Company has sold a 25% ownership interest in the Unit. For a more detailed discussion of the proceedings relating to Trimble County Unit 1 and the sale of 25% of the Unit, see Electric Operations and Notes 11 and 12 of Notes to Financial Statements under Item 8. The Clean Air Act Amendments of 1990 impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric generating plants. The Company is closely monitoring the continuing rule-making process in order to assess the precise impact of the legislation on the Company. All of the Company's coal fired boilers are equipped with sulfur dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates required by the year 2000 under the legislation. However, as part of its ongoing capital construction program, the Company has spent $10 million to date and anticipates incurring capital expenditures of approximately $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the legislation on the Company is expected to be minimal. The Company is well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities. For a more detailed discussion of the Clean Air Act and other -1- environmental issues, see Environmental Matters under this Item, Item 3, Item 7, and Note 10 of the Notes to Financial Statements under Item 8. Competition among energy suppliers is increasing. In particular, competition for off-system sales, which is based primarily on price and availability of energy, has become much more intense in recent years. The addition of electric generating capacity by other utilities in the Midwest has reduced the opportunities for the Company to make interchange sales and has heightened price competition for such sales. However, such additional capacity has made lower cost power available for purchase by the Company which, in certain instances, is at a cost lower than the variable cost of generating power from the generating stations owned by the Company. In addition, the 1992 Energy Policy Act provides utilities a wider choice of sources for their electrical supply than previously available. The Act also creates generating supply options that did not exist under previous legislation and is expected to increase competition for wholesale electric sales. See Energy Policy Act of 1992 under Item 7 for a further discussion. The Company has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; a write-off of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee involvement and training; and a major realignment and formation of new business units. Effective January 1, 1994, Energy Corp. realigned its business to reflect its outlook for rapidly emerging competition in all segments of the energy services industry. Under the realignment, a national business unit, LG&E Energy Services was formed to develop and manage all of its utility and non-utility electric power generation and concentrate on the marketing and brokering of wholesale electric power on a regional and national basis. The realignment has allowed the Company to increase its focus on customer service and develop more customer options as the utility industry becomes more competitive. As part of the business realignment, a new subsidiary was formed to market power throughout the United States. LG&E Power Marketing Inc. (LPM), an indirect wholly owned subsidiary of Energy Corp., was among the first utility-affiliated marketers in the country to secure Federal Energy Regulatory Commission (FERC) approval to sell power at market-based rates and engage in wholesale power marketing activities. The realignment does not affect Energy Corp.'s legal structure, regulation of the Company by the Kentucky Commission or Energy Corp.'s status as an exempt holding company. The Company envisions an open electricity transmission system that facilitates delivery of competitively priced power to all customers in the region. Toward that vision, the Company filed tariffs with FERC in 1994 which would provide transmission service to wholesale customers at rates, terms, and conditions which are comparable to those which the Company applies to itself. This comparable transmission service is a key feature of a more competitive electric utility industry. As part of its efforts to retain existing customers and expand to new customers, in 1994 the Company began securing long-term, mutually beneficial written contracts with key customers. By entering into such agreements, the Company is assured of a market for its energy and can prudently invest in plant and equipment upgrades and enhanced delivery services that will benefit customers and make the utility more competitive. In 1994, the Company also formalized its economic development strategic plan, integrating many of its industry-attraction efforts with that of the city of Louisville and other regional businesses. -2- By using gas storage fields strategically, the Company can buy gas when prices are low, store it, and retrieve the gas when demand is high. Accessing least cost gas was made easier in November 1993 when FERC's Order No. 636 went into effect. Previously, the Company and other utilities purchased most of their gas services from pipeline companies. The order "unbundled" gas services, allowing utilities to purchase gas, transportation, and storage services separately from many different sources. Currently, the Company buys competitively priced gas from several large producers under contracts of varying duration. By purchasing from multiple suppliers, and storing any excess gas, the Company is able to secure favorably priced gas for its customers. Without storage capacity, the Company would be forced to buy additional gas when customer demand increases, which is usually when the price is highest. See FERC Order No. 636 under Item 7 for a further discussion. The Company is experiencing some of the issues common to electric and gas utility companies, namely, increased competition for customers and costs of compliance with environmental laws and regulations. For the year ended December 31, 1994, 74% of total operating revenues was derived from electric operations and 26% from gas operations. Electric and gas operating revenues and the percentages by classes of service on a combined basis for this period were as follows:
(Thousands of $) ------------------------------------ Electric Gas Combined % Combined -------- --- -------- ---------- Residential. . . . . . . . . . . $194,145 $110,553 $304,698 43% Commercial . . . . . . . . . . . 155,847 40,474 196,321 28 Industrial . . . . . . . . . . . 108,004 27,956 135,960 19 Public authorities . . . . . . . 53,191 12,930 66,121 10 ------- ------- ------- --- Total-ultimate consumers. . . 511,187 191,913 703,100 100% --- --- Sales for resale . . . . . . . . 42,720 -- 42,720 Gas transportation-net . . . . . -- 6,759 6,759 Miscellaneous. . . . . . . . . . 5,039 1,457 6,496 ------- ------- ------- Total . . . . . . . . . . . . $558,946 $200,129 $759,075 ------- ------- -------
See Note 13 of Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 1994. Electric Operations The sources of electric operating revenues and the volumes of sales for the three years ended December 31, 1994, were as follows:
1994 1993 1992 ---- ---- ---- ELECTRIC OPERATING REVENUES (Thousands of $): Residential . . . . . . . . . . . . . $ 194,145 $ 195,273 $ 174,559 Small commercial and industrial . . . 70,916 70,106 66,183 Large commercial. . . . . . . . . . . 84,931 84,231 80,041 Large industrial. . . . . . . . . . . 108,004 104,506 101,699 Public authorities. . . . . . . . . . 53,191 52,183 49,599 -------- ------- ------- Total-ultimate consumers . . . . . 511,187 506,299 472,081 Sales for resale. . . . . . . . . . . 42,720 58,959 45,698 Miscellaneous . . . . . . . . . . . . 5,039 4,952 3,890 -------- -------- -------- Total. . . . . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669 -------- -------- -------- -------- -------- --------
-3-
1994 1993 1992 ---- ---- ---- ELECTRIC SALES (Thousands of kwh): Residential . . . . . . . . . . . . . . . 3,204,330 3,230,463 2,923,517 Small commercial and industrial . . . . . 1,073,152 1,056,977 1,010,830 Large commercial. . . . . . . . . . . . . 1,729,668 1,696,686 1,624,441 Large industrial. . . . . . . . . . . . . 2,874,411 2,736,269 2,671,212 Public authorities. . . . . . . . . . . . 1,085,741 1,053,928 1,004,911 ---------- ---------- ---------- Total-ultimate consumers . . . . . . . 9,967,302 9,774,323 9,234,911 Sales for resale. . . . . . . . . . . . . 2,315,311 3,299,510 3,234,758 ---------- ---------- ---------- Total. . . . . . . . . . . . . . . . . 12,282,613 13,073,833 12,469,669 ---------- ---------- ---------- ---------- ---------- ----------
At December 31, 1994, the Company had 340,810 electric customers. The Company uses efficient coal-fired boilers that are fully equipped with sulfur dioxide removal systems to generate electricity. The Company's system wide emission rate for sulfur dioxide in 1994 was approximately .84 lbs./MMBtu of heat input, which is significantly below the Phase II limit of 1.2 lbs./MMBtu established by the Clean Air Act Amendments for the year 2000. On Monday, August 30, 1993, the Company set a record local peak load of 2,239 Mw, when the temperature at the time of peak reached 94 degrees F (average for the day was 84 degrees F). The 1994 maximum local peak load of 2,219 Mw occurred on Wednesday, June 15, when the temperature at the time of peak was 95 degrees F (average for the day was 85 degrees F). The record system peak of 3,223 Mw (which included purchases from and short-term sales to other electric utilities) occurred on Thursday, May 30, 1991. The Company's current reserve margin is 16%. At February 28, 1995, the Company owned steam and combustion turbine generating facilities with a capacity of 2,613 Mw and an 80 Mw hydroelectric facility on the Ohio River. See Item 2, Properties. The Company is a participating owner with 14 other electric utilities of Ohio Valley Electric Corporation (OVEC) whose primary customer is the Portsmouth Area uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio. The Company has electric transmission interconnections and/or interconnection/interchange agreements with PSI Energy, Kentucky Utilities Company, Southern Indiana Gas and Electric Company, The Cincinnati Gas & Electric Company, Indiana Michigan Power Company, OVEC, Big Rivers Electric Corporation, Tennessee Valley Authority, Wabash Valley Power Association, Indiana Municipal Power Agency, East Kentucky Power Cooperative (East Kentucky), Illinois Municipal Electric Agency, Jacksonville Electric Authority, and Ogelthorpe Power Corporation providing for various interchanges, emergency services, and other working arrangements. The Company entered into an agreement with East Kentucky to provide about 40 megawatts of electricity to Gallatin Steel Company's (Gallatin) new steel mill in north central Kentucky. The agreement will continue for 10 years and is expected to result in approximately $6 million of revenues annually. Gallatin makes steel for manufacturing plants in Kentucky. The Company will supply the electricity from its power plants in the Louisville area. This transaction was negotiated by LPM, an affiliate of the Company, and the terms of the transaction were approved by the Kentucky Commission. The Company and East Kentucky had an agreement that allowed East Kentucky to purchase power during its peak season, and the Company to sell power during its off-peak season. The -4- agreement entitled East Kentucky to buy from the Company up to 145 megawatts from mid-December to mid-February through 1994-95. On February 28, 1991, the Company sold a 12.12% ownership interest in Trimble County Unit 1 to the Illinois Municipal Electric Agency (IMEA), based in Springfield, Illinois, which is an agency of 30 municipalities that own and operate their own electric systems. On February 1, 1993, the Indiana Municipal Power Agency (IMPA), based in Carmel, Indiana, purchased a 12.88% interest in the Trimble County Unit. IMPA is composed of 31 municipalities that have joined together to meet their long-term electric power needs. Both IMEA and IMPA pay their proportionate share for operation and maintenance expenses of the Unit and for fuel and reactant used. They are also responsible for their proportionate share of incremental capital assets acquired. Electric and magnetic fields (sometimes referred to as EMF) surround electric wires or conductors of electricity such as electrical tools, household wiring and appliances, and high voltage electric transmission lines such as those owned by the Company. Certain studies have suggested a possible association between electric and magnetic fields and adverse health effects. The Electric Power Research Institute, of which the Company is a participating member, has expended approximately $75 million since 1987 in its investigation and research with regard to possible health effects posed by exposure to electric and magnetic fields. Gas Operations The sources of gas operating revenues and the volumes of sales for the three years ended December 31, 1994, were as follows:
1994 1993 1992 ---- ---- ---- GAS OPERATING REVENUES (Thousands of $): Residential . . . . . . . . . . . . . . $ 110,553 $ 112,508 $ 96,175 Commercial. . . . . . . . . . . . . . . 40,474 43,568 36,801 Industrial. . . . . . . . . . . . . . . 27,956 28,310 26,156 Public authorities. . . . . . . . . . . 12,930 13,846 13,884 -------- ------- -------- Total-ultimate consumers. . . . . . . 191,913 198,232 173,016 Gas transportation-net. . . . . . . . . 6,759 5,147 4,169 Miscellaneous . . . . . . . . . . . . . 1,457 1,536 1,341 -------- ------- ------- Total . . . . . . . . . . . . . . . . $ 200,129 $ 204,915 $ 178,526 -------- ------- ------- -------- ------- ------- GAS SALES (Millions of cu. ft.): Residential . . . . . . . . . . . . . . 22,935 24,330 22,465 Commercial. . . . . . . . . . . . . . . 9,450 10,308 9,527 Industrial. . . . . . . . . . . . . . . 7,505 7,817 8,077 Public authorities. . . . . . . . . . . 3,268 3,515 3,864 ------- ------- ------- Total-ultimate consumers. . . . . . . 43,158 45,970 43,933 Gas transported . . . . . . . . . . . . 6,854 5,249 4,155 ------- ------- ------- Total . . . . . . . . . . . . . . . . 50,012 51,219 48,088 ------- ------- ------- ------- ------- -------
At December 31, 1994, the Company had 265,688 gas customers. The Company has underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers. -5- Reflecting the changing nature of the gas business, a number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through the Company's distribution system. Generally, transportation of natural gas for the Company's customers does not have an adverse effect on earnings because of the offsetting decrease in gas supply expenses. Transportation rates are designed to make the Company economically indifferent as to whether gas is sold or merely transported. The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees F. During 1994, the maximum day gas sendout was 524,000 Mcf, occurring on January 15, when the average temperature for the day was 2 degrees F. Supply on that day consisted of 176,000 Mcf from purchases, 314,000 Mcf delivered from underground storage, and 34,000 Mcf transported for industrial customers. For further discussion, see Gas Supply. In 1994, the Company experienced its first full year operating under FERC Order No. 636. While the Company had previously been able to purchase natural gas and pipeline transportation services from Texas Gas Transmission Corporation (Texas Gas), the Company now purchases only transportation services from Texas Gas pursuant to its FERC-approved tariff and acquires its supply of natural gas from other sources. For further discussion see Gas Supply and Note 10 of Notes to Financial Statements under Item 8. Regulation and Rates The Kentucky Commission has regulatory jurisdiction over the rates and service of the Company and over the issuance of certain of its securities. The Company is a "public utility" as defined in the Federal Power Act, and is subject to the jurisdiction of the Department of Energy and the FERC with respect to the matters covered in such Act, including the sale of electric energy at wholesale in interstate commerce. In addition, the FERC has sole jurisdiction over the issuance by the Company of short-term securities. For a discussion of current regulatory matters, see Rates and Regulation under Item 7 and Notes 2 and 11 of Notes to Financial Statements under Item 8. Increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all of the Company's electric customers by means of the Company's fuel adjustment clause. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals for the purpose of additional examination and transfer of the then current fuel adjustment charge or credit to the base charges. The Commission also requires that electric utilities, including the Company, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities. The Company's gas rates contain a gas supply clause (GSC), whereby increases or decreases in the cost of gas supply are reflected in the Company's rates, subject to approval of the Kentucky Commission. The GSC procedure prescribed by order of the Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters. -6- On January 1, 1994, the Company implemented a Commission approved demand side management (DSM) program. The program contains a rate mechanism that provides for the recovery of DSM program costs, allows the Company to recover revenues due to lost sales associated with the DSM programs and provides the Company an incentive for implementing DSM programs. See Rates and Regulation under Item 7 for a further discussion of DSM. On October 7, 1994, the Company filed an application with the Kentucky Commission in which it requested approval of an environmental cost recovery surcharge to recover certain costs required to comply with the Federal Clean Air Act, as amended, and those federal, state, and local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal. Under state law, the Commission has until April 7, 1995, to rule on the application. If the Company's application is approved as filed, the surcharge will increase electric revenues by approximately $5.5 million in 1995 and $8.3 million in 1996. The Commission has previously approved environmental cost recovery surcharges for two other regulated electric utilities in Kentucky. A management audit of Louisville Gas and Electric Company, which began in September 1994, is nearing completion. Vantage Consulting Inc. is conducting the audit under contract to the Kentucky Commission. Vantage has interviewed some 300 employees and the Company has made written responses to more than 800 requests for data and documents. The final report is not expected until June. A similar audit of the Company was conducted in 1986 under a mandate from the 1984 Kentucky General Assembly that requires such audits of the Commonwealth's 10 largest utilities. As part of the corporate reorganization whereby the Company became the subsidiary of LG&E Energy Corp., the Company obtained the approval of the Kentucky Commission. The order of the Kentucky Commission authorizing the Company to reorganize into a holding company structure contains certain provisions, which, among other things, ensure the Kentucky Commission access to books and records of Energy Corp. and its affiliates which relate to transactions with the Company; require Energy Corp. and its subsidiaries to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company's customers; and preclude the Company from guaranteeing any obligations of Energy Corp. without prior written consent from the Kentucky Commission. In addition, such order provides that the Company's Board of Directors has the responsibility to use its dividend policy consistent with preserving the financial strength of the Company and that the Kentucky Commission, through its authority over the Company's capital structure, can protect the Company's ratepayers from the financial effects resulting from non-utility activities. Construction Program and Financing The Company's construction program is designed to assure that there will be adequate capacity to meet the future electric and gas needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. The Company's estimates of its construction expenditures can vary substantially due to numerous items beyond the Company's control, such as changes in rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations. -7- At December 31, 1994, the Company's embedded cost of long-term debt was 6.5% and its ratio of earnings to fixed charges was 3.14. See Exhibit 12. For a further discussion of construction expenditures and financing, see Liquidity and Capital Resources under Item 7. During the five years ended December 31, 1994, gross property additions amounted to $501 million. Internally generated funds for the five year period were sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 20% of total utility plant at December 31, 1994, and consisted of $391 million for electric properties and $110 million for gas properties. Gross retirements during the same period were $55 million, consisting of $44 million for electric properties and $11 million for gas properties. Coal Supply Approximately 90% of the Company's present electric generating capacity is coal-fired, the remainder being made up of a hydroelectric plant and combustion turbine peaking units fueled by natural gas and oil. Coal will be the predominant fuel used by the Company in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies. The Company has no nuclear generating units and has no plans to build any in the foreseeable future. The Company has entered into coal supply agreements with various suppliers for coal deliveries for 1995 and beyond. The Company normally augments its coal supply agreements with spot market purchases which, during 1994, were about 10% of total purchases. The Company has a coal inventory policy, which is in compliance with the Kentucky Commission's directives and which the Company believes provides adequate protection under most contingencies. The Company had on hand at December 31, 1994, a coal inventory of approximately 580,000 tons, or a 35 day supply. The Company expects, for the foreseeable future, to continue purchasing most of its coal from western Kentucky and southwest Indiana, which has a sulfur content in the 2%-3.5% range. The abundant supply of this relatively low priced coal, combined with present and future desulfurization technologies, is expected to enable the Company to continue to provide adequate electric service in a manner acceptable under existing environmental laws and regulations. Coal for the Company's Mill Creek plant is delivered by rail and barge, whereas deliveries to the Cane Run plant are primarily by rail and also by truck. Deliveries to the Trimble County plant are by barge only. The average delivered cost of coal purchased by the Company, per ton and per million Btu, for the periods shown were as follows:
1994 1993 1992 ---- ---- ---- Per ton . . . . . . . . . . . . . . $ 25.27 $ 26.58 $ 25.17 Per million Btu . . . . . . . . . . 1.10 1.14 1.09
-8- Gas Supply During 1994, the Company experienced its first full year of operation under FERC Order No. 636. Although the Company continues to transport natural gas supplies through Texas Gas at rates and terms regulated by the FERC, the Company now purchases its supply of natural gas from other sources. As a result of FERC Order No. 636 and effective November 1, 1993, the Company entered into new transportation service agreements with Texas Gas. These agreements provide for 30,000 MMBtu (29,268 Mcf) per day in Firm Transportation (FT) throughout the year. This FT agreement expires October 31, 1995. During the winter months, the Company also has 184,900 MMBtu (180,390 Mcf) per day in No-Notice Service (NNS); during the summer months that NNS level is 135,000 MMBtu (131,707 Mcf) per day. The Company's NNS agreements with Texas Gas incorporate terms of two, five, and eight years, and include unilateral roll-over provisions at the Company's option. These transportation services are provided by Texas Gas pursuant to its FERC-approved tariff. The Company has also entered into a series of long-term firm supply arrangements with various suppliers in order to meet its firm sales obligations. The gas supply arrangements include pricing provisions which are market-responsive. These firm supplies, in tandem with pipeline transportation services, provide the reliable and flexible supply needed to replace the bundled sales service supplied by the pipeline prior to the implementation of FERC Order No. 636. During 1995, the Company will be participating in several regulatory proceedings at FERC. In particular, the Company will be involved in reviewing Texas Gas' most recent rate filing, and Texas Gas' filing to recover certain transition costs associated with the FERC-mandated implementation of FERC Order No. 636. As a separate matter, the Kentucky Commission has indicated in an order issued in its Administrative Case No. 346 that transition costs, which are clearly identified as being related to the cost of the commodity itself, are appropriately recoverable as a gas cost through the Company's gas supply clause. See Note 10 of Notes to Financial Statements under Item 8. The Company operates five underground gas storage fields with a current working gas capacity of 14.6 million Mcf. Gas is purchased and injected into storage during the summer season and is then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter heating season. The estimated maximum deliverability from storage during the early part of the 1993-1994 heating season was approximately 373,000 Mcf per day. Deliverability decreases during the latter portion of the heating season as the storage inventory is reduced by seasonal withdrawals. The average cost per Mcf of natural gas purchased by the Company was $2.78 in 1994, $2.91 in 1993, and $2.77 in 1992. Environmental Matters Protection of the environment is a major priority for the Company. The Company engages in a variety of activities within the jurisdiction of federal, state, and local regulatory agencies. Those agencies have issued the Company permits for various activities subject to air quality, water quality, -9- and waste management laws and regulations. For the five year period ending with 1994, expenditures for pollution control facilities represented $106 million or 21% of total construction expenditures. The cost of operating and maintaining scrubber-related facilities amounted to $22 million in both 1994 and 1993. The Company's anticipated capital expenditures for 1995 to comply with environmental laws are approximately $16 million. See Note 10 of Notes to Financial Statements under Item 8 for a discussion of specific environmental proceedings affecting the Company. Labor Relations The Company's 1,625 operating, maintenance and construction employees are members of the International Brotherhood of Electrical Workers (IBEW) Local 2100. The current three-year contract will expire in November 1995. Employees The Company had 2,650 full-time employees at December 31, 1994. During the last quarter of 1993, the Company eliminated a number of full-time positions. See Note 5 of Notes to Financial Statements under Item 8 for a further discussion of this matter. ITEM 2. PROPERTIES. At February 28, 1995, the Company owned the following electric generating stations:
Year in Service Capability Rating (Kw) Steam Stations: Mill Creek-Kosmosdale, Ky. Unit 1. . . . . . . . . . . . . . . . . . 1972 303,000 Unit 2. . . . . . . . . . . . . . . . . . 1974 301,000 Unit 3. . . . . . . . . . . . . . . . . . 1978 386,000 Unit 4. . . . . . . . . . . . . . . . . . 1982 466,000 1,456,000 ------- Cane Run-near Louisville, Ky. Unit 3 (natural gas only) . . . . . . . . 1958 115,000 Unit 4. . . . . . . . . . . . . . . . . . 1962 155,000 Unit 5. . . . . . . . . . . . . . . . . . 1966 168,000 Unit 6. . . . . . . . . . . . . . . . . . 1969 240,000 678,000 ------- Trimble County-Bedford, Ky. Unit 1. . . . . . . . . . . . . . . . . . 1990 371,000 (1) Combustion Turbine Generators (Peaking capability): Zorn. . . . . . . . . . . . . . . . . . . . 1969 16,000 Paddy's Run . . . . . . . . . . . . . . . . 1968 43,000 Cane Run. . . . . . . . . . . . . . . . . . 1968 16,000 Waterside . . . . . . . . . . . . . . . . . 1964 33,000 108,000 ------ --------- 2,613,000 --------- --------- (1) Amount shown represents the Company's 75% interest in the Unit. See Note 12 of Notes to Financial Statements, Jointly Owned Electric Utility Plant, under Item 8 for a discussion of the sale of 25% of the Unit to IMEA and IMPA. The Company is responsible for operation of the Unit and is reimbursed by IMEA and IMPA for expenditures related to the Unit based on their proportionate share of ownership interest.
-10- The Company's steam stations consist mainly of coal-fired units except for Cane Run Unit 3 which must use natural gas because of restrictions mandated by environmental regulations. The Company also owns an 80 Mw hydroelectric generating station located in Louisville, operated under license issued by the FERC. At December 31, 1994, the Company's electric transmission system included 21 substations with a total capacity of approximately 10,623,697 Kva and approximately 648 structure miles of lines. The electric distribution system included 83 substations with a total capacity of approximately 3,068,277 Kva, 3,505 structure miles of overhead lines, 233 miles of underground conduit, and 5,335 miles of underground conductors. The Company's gas transmission system includes 177 miles of transmission mains, and the gas distribution system includes 3,312 miles of distribution mains. The Company operates underground gas storage facilities with a current working gas capacity of approximately 14.6 million Mcf. See Gas Supply under Item 1. In 1990, the Company entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease is for a period of 15 years and is scheduled to expire June 30, 2005. Other properties owned by the Company include office buildings, service centers, warehouses, garages, and other structures and equipment, the use of which is common to both the electric and gas departments. The trust indenture securing the Company's First Mortgage Bonds constitutes a direct first mortgage lien upon substantially all property owned by the Company. ITEM 3. LEGAL PROCEEDINGS. Rates, Regulatory Matters, and Trimble County Generating Plant For a discussion of current regulatory matters and a detailed discussion of the current status concerning Trimble County Unit 1, see Rates and Regulation under Item 7 and Notes 2 and 11 of Notes to Financial Statements under Item 8. Statewide Power Planning As required by the regulations of the Kentucky Commission, on November 15, 1993, the Company filed its 1993 biennial Integrated Resource Plan with the Kentucky Commission. The plan, which updates the Company's first Integrated Resource Plan filed in 1991, proposes to meet customers' future demand through 2007 by adding resources in small increments such as short-term power purchases (1996-1999), a customer-owned standby generation program (1997), two combustion turbines (1999-2000), an air conditioner load controls program (1997, 2001-2003), an upgrade to the Company's existing hydroelectric plant (2003), and a compressed air energy storage plant (2004). The Kentucky Commission staff is reviewing the Company's plan, and is expected to issue its report -11- and recommendations concerning the plan during the first quarter of 1995. The Kentucky Commission's regulations do not require it to hold any hearings or issue any formal orders regarding the plan. Environmental For a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run generating plants, manufactured gas plant sites, and certain other environmental issues, see Note 10 of Notes to Financial Statements under Item 8. Other The Company is a defendant in lawsuits seeking compensatory and, in certain instances, punitive damages. To the extent that damages are assessed in any of these lawsuits, the Company believes that its insurance coverage is adequate and that the effect of any such damages will not be material to the Company's results of operation or financial position. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None ----------------------------- -12- Executive Officers of the Company. Effective Date of Election to Name Age Position Present Position - ---- --- -------- ----------------- Roger W. Hale 51 Chairman of the Board and Chief Executive Officer January 1, 1992 Victor A. Staffieri 39 President January 1, 1994 John R. McCall 51 Executive Vice President, General Counsel and Corporate Secretary July 1, 1994 David R. Carey 41 Senior Vice President, Operations January 1, 1994 M. Lee Fowler 58 Vice President and Controller September 1, 1988 Wendy C. Heck 41 Vice President, Information Services January 1, 1994 Chris Hermann 47 Vice President and General Manager, Wholesale Electric Business January 1, 1993 Rebecca L. Holt 35 Vice President, Gas Service Business February 15, 1995 Charles A. Markel III 47 Treasurer January 1, 1993 The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the Annual Meeting of Stockholders, scheduled to be held April 25, 1995. There are no family relationships between executive officers of the Company. Mr. Hale, Mr. Carey, Mr. Fowler, Ms. Heck, Mr. Hermann, and Mr. Markel have been employed for more than five years in executive or management positions with the Company. Prior to election to the position shown in the table, the following executive officers held other positions with the Company since January 1, 1990: Mr. Hale was President and Chief Executive Officer prior to February 1990, and Chairman of the Board, President and Chief Executive Officer thereafter; Mr. Carey was Vice President-Marketing and Sales prior to July 1990, Vice President-Marketing and Planning prior to January 1992, Vice President-Marketing and General Manager, Electric Service, prior to January 1993, and Vice President and General Manager, Retail Electric Business thereafter; Ms. Heck was Vice President-Internal Auditing prior to January 1992, Vice President-Fuels and Operating Services prior to January 1993, and Vice President-Fuels and Information Services thereafter; Mr. Hermann was General Manager-Power Production prior to January 1992 and General Manager-Wholesale Electric thereafter; Mr. Markel was Vice President and Treasurer prior to March 1990, Vice President-Finance and Treasurer prior to January 1992, and Senior Vice President and Chief Financial Officer thereafter. Effective January 1993, Mr. Markel was named Corporate Vice President-Finance and Treasurer of the parent company, LG&E Energy Corp. -13- Prior to election to his current position, Mr. Staffieri was Senior Vice President-Public Policy, and General Counsel of the Company, and prior to November 1992, Senior Vice President, General Counsel and Corporate Secretary. Prior to March 1992, Mr. Staffieri was employed by Long Island Lighting Company and held the position of General Counsel and Secretary. Prior to election to his current position, Mr. McCall was Partner and Litigation Chairman of Brown, Todd & Heyburn, a law firm. Prior to election to her current position, Ms. Holt was employed by South Carolina Electric and Gas Company and held the position of General Manager, Gas Operations from July 1994 to February 1995, Division Manager, Central Division-Gas Operations prior to July 1994, General Manager, Northern Division-Gas Operations prior to February 1992, and Manager, Columbia Gas Operations prior to July 1990. -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:
1994 1993 ---- ---- (Thousands of $) First Quarter. . . . . . . . $17,500 $17,000 Second Quarter . . . . . . . 17,500 16,500 Third Quarter. . . . . . . . - 16,500 Fourth Quarter . . . . . . . 18,000 17,000
ITEM 6. SELECTED FINANCIAL DATA.
Years Ended December 31 (Thousands of $) ------------------------------------------------------------------------------ 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Operating Revenues . . . . . . . . . . $759,075 $775,125 $700,195 $708,706 $698,758 ------- ------- ------- ------- ------- Net Operating Income: Before Non-Recurring Charges. . . . 149,653 136,118 125,829 142,730 137,717 Non-Recurring Charges . . . . . . . 38,613 - - - - ------- ------- ------- ------- ------- Total. . . . . . . . . . . . . . 111,040 136,118 125,829 142,730 137,717 ------- ------- ------- ------- ------- Net Income: Before Non-Recurring Charges, etc.. 94,423 90,535 73,793 94,643 83,450 Non-Recurring Charges, Charitable Foundation, etc.. . . 32,734 - - - - Cumulative Effect of Accounting Change. . . . . . . . (3,369) - - - 18,236 ------- ------- ------- ------- ------- Total Net Income . . . . . . . . 58,320 90,535 73,793 94,643 101,686 ------- ------- ------- ------- ------- Net Income Available for Common Stock . . . . . . . . . . . . 52,492 84,554 66,620 85,179 92,221 Total Assets . . . . . . . . . . . . . 1,966,590 1,974,584 1,960,860 1,936,909 1,985,872 Long-Term Obligations (including amounts due within one year) . . . . 662,800 662,800 686,262 687,662 688,250
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION. The following discussion and analysis by management focuses on those factors that had a material effect on the Company's financial results of operations and financial condition during 1994, 1993, and 1992 and should be read in connection with the financial statements and notes thereto. -15- Results of Operations Net Income Available for Common Stock In 1994 the Company's net income available for common stock decreased $32.1 million. This decrease was due to the write-off of certain non-recurring items ($23.8 million), the expense of establishing a charitable foundation ($8.9 million), and the adoption of Statement of Financial Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS ($3.4 million). Without consideration of the charges against income discussed above, the Company's 1994 income would have increased $3.9 million over 1993. This improvement is primarily due to increased sales of electricity to retail customers and reduced interest on debt due to favorable refinancing activities in 1993. The $17.9 million increase in earnings for 1993 over 1992 resulted primarily from increased electric sales attributable to warmer summer weather experienced in 1993, higher sales to other utilities, reduced costs for debt and preferred stock attributable to favorable refinancing activities, and a gain recognized on the sale of the remaining disallowed portion of the Trimble County plant to the Indiana Municipal Power Agency (IMPA). These items were partially offset by a higher level of operation and maintenance expense. Rates and Regulation The Company is subject to the jurisdiction of the Public Service Commission of Kentucky (Kentucky Commission or Commission) in virtually all matters related to electric and gas utility regulation, and as such, its accounting is subject to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71). Given the Company's competitive position in the market and the status of regulation in the state of Kentucky, the Company has no plans or intentions to discontinue its application of SFAS No. 71. See Note 2 of Notes to Financial Statements under Item 8. The Company last filed for a rate increase with the Commission in June 1990 based on the test-year ended April 30, 1990. A final order was issued in September 1991 that effectively granted the Company an annual increase in rates of $6.8 million ($6.1 million electric and $.7 million gas). The Commission's order authorized a rate of return on common equity of 12.5%. On October 7, 1994, the Company filed an application with the Kentucky Commission in which it requested approval of an environmental cost recovery surcharge to recover certain costs required to comply with the Federal Clean Air Act, as amended, and those federal, state, and local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal. Under state law, the Commission has until April 7, 1995, to rule on the application. If the Company's application is approved as filed, the surcharge will increase electric revenues by approximately $5.5 million in 1995 and $8.3 million in 1996. The Commission has previously approved environmental cost recovery surcharges for two other regulated electric utilities in Kentucky. On January 1, 1994, the Company implemented a Commission approved demand side management (DSM) program that the Company, the Kentucky Attorney General, the Jefferson County Attorney, and representatives of several customer-interest groups had filed with the Commission. -16- Under the agreement, the Company will commit up to $3.3 million over three years (from 1994 through 1996) for initial programs that include a residential energy conservation and education program and a commercial conservation audit program. Future programs will be developed through a formal collaborative process. The agreement contains a rate mechanism that will (1) provide the Company concurrent recovery of DSM program costs, (2) provide the Company an incentive for implementing DSM programs, and (3) allow the Company to recover revenues due to lost sales associated with the DSM programs. Revenues from lost sales to residential customers are collected through a "decoupling mechanism". The Company's residential decoupling mechanism breaks the link between the level of the Company's residential kilowatt-hour and Mcf sales and its non-fuel revenues. Under traditional regulation, a utility's revenue varies with changes in its level of kilowatt-hour or Mcf sales. The residential decoupling mechanism allows the Company to recover a predetermined level of revenue per residential customer based on the rate set in the Company's last rate case, which will not vary with the level of kilowatt-hour or Mcf sales. Residential revenues will be adjusted to reflect (1) changes in the number of residential customers and (2) a pre-established annual growth factor in residential revenue per customer. Decoupling, in effect, removes the impact on the Company's non-fuel revenues from changes in kilowatt-hour or Mcf sales due to weather, fluctuations in the economy, and conservation efforts. Under this mechanism, if actual sales produce lower revenues than are produced by the predetermined per-customer amount, the difference is deferred for recovery from customers through an adjustment in rates over a period that will not exceed two years. Conversely, if actual sales produce more revenues than would be realized using the predetermined per-customer amount, the difference will be returned to customers through subsequent rate adjustments over a period not to exceed two years. Residential revenues reported in the financial statements for 1994 through 1996 will be determined in accordance with the predetermined amount per customer plus growth, and recovery of fuel and gas costs. The difference between the revenues shown in the financial statements and the amounts billed to customers will be deferred for future recovery from, or return to, customers. As more fully discussed in Note 11 of Notes to Financial Statements under Item 8, the Commission has scheduled a formal hearing on May 9, 1995, to determine the appropriate ratemaking treatment to exclude 25% of the Trimble County plant from customer rates. The Company is unable to predict the outcome of the Commission proceedings, or the amount of additional refunds or recoveries, if any, that may be ordered. On May 24, 1993, the Federal Energy Regulatory Commission (FERC) gave final approval for a market-based rate tariff and two transmission service tariffs that were filed by the Company. This market-based tariff enables the Company to sell up to 75 Mw of firm generation capacity at market-based rates. It also enables the Company to sell an unlimited amount of non-firm power at market- based rates, as long as the power is from the Company's own generation resources. In 1994, the Company made its first power sales under its market-based tariff. Although the Company has both firm and non-firm open access transmission rate schedules which were approved by FERC in 1994, the Company took the additional steps of filing a new network transmission service and a new flexible point-to-point transmission service to provide transmission service to other parties comparable to the transmission service the Company provides itself. -17- The Company is currently undergoing a planned management and operations audit initiated by the Kentucky Commission. The audit results will include an evaluation of the Company's operations and identify opportunities for improvements. An audit report is scheduled to be issued by mid-1995. Revenues A comparison of operating revenues for the years 1994 and 1993 with the immediately preceding years reflects both increases and decreases, which have been segregated by the following principal causes (in thousands of $):
Increase (Decrease) From Prior Period -------------------------------------------------------------- Electric Revenues Gas Revenues ------------------------- ------------------------ Cause 1994 1993 1994 1993 ----- ---- ---- ---- ---- Sales to Ultimate Consumers: Fuel and gas supply adjustments, etc. . . $ (841) $ 6,832 $ 1,823 $19,479 Demand side management/decoupling . . . . 1,853 - 3,997 - Variation in sales volumes. . . . . . . . 3,876 27,386 (12,139) 5,737 ------- ------ ------- ------ Total. . . . . . . . . . . . . . . . . 4,888 34,218 (6,319) 25,216 Sales for resale . . . . . . . . . . . . . . . (16,239) 13,261 - - Gas transportation-net . . . . . . . . . . . . - - 1,612 978 Other. . . . . . . . . . . . . . . . . . . . . 87 1,062 (79) 195 ------- ------ ------- ------ Total. . . . . . . . . . . . . . . . . $(11,264) $48,541 $ (4,786) $26,389 ------- ------ ------- ------ ------- ------ ------- ------
The Company's electric revenues decreased in 1994 compared with 1993 primarily because of a decrease in the sales of electricity for resale. Gas sales to ultimate consumers decreased 6% due primarily to the warmer than normal weather in the last quarter of 1994. Electric revenues increased in 1993 primarily because of the warmer summer weather. Sales of electricity for resale increased over 1992 levels due to the Company's aggressive efforts in marketing off-system sales of energy. The increase in gas sales for 1993 is largely attributable to cooler winter weather in the region and customer growth. Expenses Fuel for electric generation and gas supply expenses 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 the approval by the Commission. Fuel expenses decreased $5.8 million (4%) in 1994 primarily because of a decrease in the cost of coal burned ($3.9 million) and decreased generation of 3%. Fuel expenses for 1993 increased $13.8 million over 1992 because of increased generation. The average delivered cost per ton of coal purchased was $25.27 in 1994, $26.58 in 1993, and $25.17 in 1992. Power purchased decreased $7.5 million in 1994 primarily because less power was wheeled for other utilities as a result of milder weather in the region. The increase of $5.2 million in 1993 was largely attributable to more power purchased because of wheeling arrangements with other utilities. -18- Gas supply expenses decreased $7.5 million (5%) in 1994 due mainly to a decrease in the volume of gas delivered to the distribution system ($9.2 million), partially offset by an increase in net gas supply cost ($1.7 million). Gas supply expenses for 1993 increased $23.5 million primarily because of an increase in net gas supply cost ($17.6 million) and a 5% increase in the volume of gas delivered to the distribution system. The average unit cost per Mcf of purchased gas was $2.78 in 1994, $2.91 in 1993, and $2.77 in 1992. Other operation expenses decreased $.5 million in 1994 mainly as a result of decreases in various administrative expenses ($1.8 million), partially offset by increased costs to operate electric generating plants and gas and electric distribution systems ($.7 million), and an increase in the provision for uncollectible accounts ($.6 million). Maintenance expenses were up only slightly over 1993. In 1993, operation expenses increased $6 million (5%) over 1992 primarily because of increased costs of electric generating plants ($2 million), and an increase in various administrative expenses ($4.2 million). The 1993 maintenance expenses increased $1.5 million (3%), primarily due to increased repairs at the electric generating plants. Non-recurring charges 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 Notes 2 and 3 of Notes to Financial Statements under Item 8. Depreciation and amortization increased in both 1994 and 1993 because of additional depreciable plant in service. Variations in income tax expenses are largely attributable to changes in pre-tax income and an increase in the corporate Federal income tax rate from 34% to 35%, effective January 1, 1993. Other income and (deductions) increased $.5 million in 1994 partially due to recognition of a gain on the sale of construction equipment. Other income and (deductions) increased in 1993 primarily because of a $3.2 million after-tax gain recorded on the sale of a 12.88% ownership interest in the Trimble County plant to IMPA. See Note 7 of Notes to Financial Statements under Item 8 for further detail. Contribution to the charitable foundation reflects the expense associated with establishing a tax-exempt foundation during 1994. Contributions made from this Foundation will not be charged against income, and therefore, will not affect the Company's net income in the future. See Note 3 of Notes to Financial Statements under Item 8. Interest charges decreased in 1994 because of the lower composite interest rate on outstanding debt, which reflects the full year effect of the Company's 1993 aggressive program to refinance approximately $205 million of outstanding debt at lower interest rates. Interest charges also decreased in 1993 as compared to 1992 primarily because of this refinancing program. Since 1992, an immaterial component of interest expense has been the cost associated with interest rate swaps. See Liquidity and Capital Resources. Preferred dividends reflect the lower dividends that resulted from the Company's refunding its $25 million, $8.90 Series with a $5.875 Series in May 1993. -19- The rate of inflation may have a significant impact on the Company's operations, its ability to control costs, and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results. LIQUIDITY AND CAPITAL RESOURCES The Company's need for capital funds is primarily related to the construction of plant and equipment necessary to meet the needs of electric and gas utility customers and protection of the environment. 1994 Capital Requirements New construction expenditures for 1994 were $95 million compared with $99 million for 1993 and $101 million for 1992. Past Financing Activities During 1994, 1993, and 1992, the Company's primary source of capital was internally generated funds from operating cash flows. Internally generated funds provided financing for 100% of the Company's construction expenditures for 1994 and 1993 and 87% of utility capital expenditures in 1992. Variations in accounts receivable and accounts payable are not generally significant indicators of the Company's liquidity, as such variations are primarily attributable to fluctuations in weather in the Company's service territory, which has a direct effect on sales of electricity and gas. In 1994, accounts receivable and accounts payable were lower due to warmer weather in the last quarter of the year as compared to 1993. In 1993, the Company refinanced approximately $205 million of its long-term debt and $25 million of its preferred stock. These refinancings produced significant savings from lower interest rates and preferred dividend rates in 1994 and 1993. See Note 8 of Notes to Financial Statements under Item 8. The Company's liquidity was also positively affected in 1993 by the sale of a 12.88% portion of the Company's Trimble County Generating Unit. At December 31, 1994, marketable securities classified as Other Property and Investments amounted to $50 million. See Note 4 of Notes to Financial Statements under Item 8. The Company has outstanding interest rate swap agreements with a notional amount of $30 million. These swaps were entered into as a standard hedging device in connection with the 1992 issuance of the Company's Pollution Control Bonds Series S, due September 1, 2017. The swaps are designed to reduce the Company's exposure to interest rate risk. Under the agreements, the Company pays a fixed rate of 4.35% on $15 million for a five-year period and 4.74% on $15 million for a seven-year period resulting in interest payments based on a composite rate of 4.55% in 1994, 1993, and 1992. In return, the Company receives a floating rate based on the weighted average JJ Kenny index. The Company received interest at composite rates of 2.84%, 2.38%, and 2.73% in 1994, 1993, and 1992, respectively. -20- Future Capital Requirements Future financing requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate increases allowed by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. The Company estimates construction expenditures will total $200 million for 1995 and 1996. In addition, expected capital requirements for 1996 include $16 million to retire long-term debt. Future Sources of Financing Internally generated funds from operations are expected to fund substantially all anticipated construction expenditures in 1995 and 1996. At December 31, 1994, the Company had unused lines of credit of $145 million for which it pays commitment fees. These credit facilities are scheduled to expire at various periods during 1995 and 1996 and management intends to renegotiate them when they expire. To the extent permanent financings are needed in 1995 and 1996, the Company expects that it will have ready access to the securities markets to raise needed funds. Environmental Matters The Clean Air Act Amendments of 1990 impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. All of the Company's coal-fired boilers are equipped with sulfur dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates required by the year 2000 under the legislation. However, as part of its ongoing construction program, the Company has spent $10 million to date and anticipates incurring capital expenditures of approximately $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the legislation on the Company is expected to be minimal. The Company is well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities. Reference is made to Note 10 of Notes to Financial Statements, Environmental, under Item 8 for a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run electric generating plants, manufactured gas plant sites, and certain other environmental issues. Energy Policy Act of 1992 The Energy Policy Act of 1992 is designed to give utilities a wider choice of sources for their electrical supply than previously available, while creating generating supply options that did not exist under the old law. In passing this legislation, Congress also anticipated that greater competition among electric supply options should result in lower consumer rates. The Company plans to aggressively pursue opportunities created by a more competitive electric power market. -21- FERC Order No. 636 In 1994, the Company experienced its first full year of operations under the provisions of Order No. 636. During 1994, the Company paid and began recovering from its customers approximately $2.8 million in transition costs under Order No. 636. It is estimated that $6 million to $8 million in additional transition costs will be incurred by the Company during 1995, and these costs are also expected to be recovered from customers. See FERC Order No. 636 in Note 10 of Notes to Financial Statements under Item 8 for further discussion. FUTURE OUTLOOK Business Realignment Effective January 1, 1994, LG&E Energy Corp. realigned its business to reflect its outlook for rapidly emerging competition in all segments of the energy services industry. Under the realignment, a national business unit, LG&E Energy Services was formed to develop and manage all of its utility and non-utility electric power generation and concentrate on the marketing and brokering of wholesale electric power on a regional and national basis. Louisville Gas and Electric Company, LG&E Energy Corp.'s principal subsidiary, will increase its focus on customer service and develop more customer options as the utility industry becomes more competitive. As part of the business realignment, a new subsidiary was formed to market power throughout the United States. LG&E Power Marketing Inc. (LPM), an indirect wholly owned subsidiary of LG&E Energy Corp., was among the first utility-affiliated marketers in the country to secure FERC approval to sell power at market-based rates and engage in wholesale power marketing activities. The realignment does not affect LG&E Energy Corp.'s legal structure, regulation of the Company by the Commission or LG&E Energy Corp.'s status as an exempt holding company. Gallatin Steel Company The Company entered into an agreement with East Kentucky Power Cooperative, Inc. to provide about 40 megawatts of electricity to Gallatin Steel Company's (Gallatin) new steel mill in north central Kentucky. The agreement will continue for 10 years and is expected to result in approximately $6 million of revenues annually. Gallatin makes steel for manufacturing plants in Kentucky. The Company will supply the electricity from its power plants in the Louisville area. This transaction was negotiated by LPM, and the terms of the transaction were approved by the Commission. Competition The Company has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; a write-off of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee involvement and training; and a major realignment and formation of new business units. -22- ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Thousands of $)
Years Ended December 31 ------------------------------------------------------ 1994 1993 1992 ---- ---- ---- Operating Revenues Electric . . . . . . . . . . . . . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669 Gas. . . . . . . . . . . . . . . . . . . . . . . . . . 200,129 204,915 178,526 ------- ------- ------- Total operating revenues (Note 1). . . . . . . . . . 759,075 775,125 700,195 ------- ------- ------- Operating Expenses Fuel for electric generation . . . . . . . . . . . . . 143,602 149,436 132,551 Power purchased. . . . . . . . . . . . . . . . . . . . 9,754 17,228 12,044 Gas supply expenses. . . . . . . . . . . . . . . . . . 131,561 139,054 115,521 Other operation expenses . . . . . . . . . . . . . . . 136,214 136,693 130,740 Maintenance. . . . . . . . . . . . . . . . . . . . . . 48,731 48,414 46,931 Non-recurring charges (Note 3) . . . . . . . . . . . . 38,613 - - Depreciation and amortization. . . . . . . . . . . . . 82,519 79,655 76,903 Federal and State income taxes (Note 6). . . . . . . . 39,922 52,334 43,840 Property and other taxes . . . . . . . . . . . . . . . 17,119 16,193 15,836 ------ ------ ------ Total operating expenses . . . . . . . . . . . . . . 648,035 639,007 574,366 ------- ------- ------- Net Operating Income . . . . . . . . . . . . . . . . . . 111,040 136,118 125,829 Other Income and (Deductions) (Note 7) . . . . . . . . . 2,451 1,913 (2,203) Contribution to Charitable Foundation - net (Note 3) . . 8,946 - - Interest Charges . . . . . . . . . . . . . . . . . . . . 42,856 47,496 49,833 ------ ------ ------ Income before Cumulative Effect of a Change in Accounting Principle . . . . . . . . . . . . . . . . . 61,689 90,535 73,793 Cumulative Effect of a Change in Accounting for Post-Employment Benefits, net of income taxes of $2,280 (Note 5) . . . . . . . . . . . . . . . . . . (3,369) - - ------ ------ ------ Net Income . . . . . . . . . . . . . . . . . . . . . . . 58,320 90,535 73,793 Preferred Stock Dividends. . . . . . . . . . . . . . . . 5,828 5,981 7,173 ------ ------ ------ Net Income Available for Common Stock. . . . . . . . . . $ 52,492 $ 84,554 $ 66,620 ------ ------ ------ ------ ------ ------
STATEMENTS OF RETAINED EARNINGS (Thousands of $) Years Ended December 31 ----------------------------------------------------- 1994 1993 1992 ---- ---- ---- Balance January 1. . . . . . . . . . . . . . . . . . . . $ 194,903 $ 178,667 $ 181,694 Add net income . . . . . . . . . . . . . . . . . . . . . 58,320 90,535 73,793 ------- ------- ------- 253,223 269,202 255,487 ------- ------- ------- Deduct: Cash dividends declared on stock: 5% cumulative preferred . . . . . . . . . . . . 1,075 1,075 1,076 7.45% cumulative preferred. . . . . . . . . . . 1,598 1,598 1,598 $8.72 cumulative preferred. . . . . . . . . . . - - 454 $8.90 cumulative preferred. . . . . . . . . . . - 1,113 2,225 $9.54 cumulative preferred. . . . . . . . . . . - - 497 Auction rate cumulative preferred . . . . . . . 1,686 1,322 1,323 $5.875 cumulative preferred . . . . . . . . . . 1,469 873 - Common. . . . . . . . . . . . . . . . . . . . . 53,500 67,500 67,500 Preferred stock redemption expense. . . . . . . . - 818 2,147 ------- ------- ------- 59,328 74,299 76,820 ------- ------- ------- Balance December 31. . . . . . . . . . . . . . . . . . . $ 193,895 $ 194,903 $ 178,667 ------- ------- ------- ------- ------- -------
The accompanying notes are an integral part of these financial statements. -23-
LOUISVILLE GAS AND ELECTRIC COMPANY BALANCE SHEETS (Thousands of $) ASSETS December 31 ---------------------------------------- 1994 1993 ---- ---- Utility Plant, at original cost Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,084,334 $ 2,019,139 Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280,877 260,485 Common . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137,662 132,692 --------- --------- 2,502,873 2,412,316 Less: Reserve for depreciation. . . . . . . . . . . . . . . . . . 881,861 823,141 --------- --------- 1,621,012 1,589,175 Construction work in progress. . . . . . . . . . . . . . . . . . . 35,022 51,785 --------- --------- 1,656,034 1,640,960 --------- --------- Other Property and Investments - less reserve (Note 4) 50,681 22,067 --------- --------- Current Assets Cash and temporary cash investments. . . . . . . . . . . . . . . . 39,138 44,105 Accounts receivable - less reserve of $1,203 in 1994 and $1,474 in 1993. . . . . . . . . . . . . . . . 86,058 104,397 Materials and supplies - at average cost Fuel (predominantly coal). . . . . . . . . . . . . . . . . . . . 13,869 12,075 Gas stored underground . . . . . . . . . . . . . . . . . . . . . 31,354 33,370 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,299 40,357 Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . . . . 253 360 --------- --------- 207,971 234,664 --------- --------- Deferred Debits and Other Assets Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . 7,776 8,076 Regulatory assets (Note 2) . . . . . . . . . . . . . . . . . . . . 31,726 61,642 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,402 7,175 --------- --------- 51,904 76,893 --------- --------- $ 1,966,590 $ 1,974,584 --------- --------- --------- --------- CAPITAL AND LIABILITIES Capitalization (see Statements of Capitalization) Common equity. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 616,478 $ 619,237 Cumulative preferred stock . . . . . . . . . . . . . . . . . . . . 116,716 116,716 Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . 662,862 662,879 --------- --------- 1,396,056 1,398,832 --------- --------- Current Liabilities Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . 70,770 93,551 Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . 19,567 18,878 Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . 8,247 9,494 Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . 13,394 12,864 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,277 11,127 --------- --------- 122,255 145,914 --------- --------- Deferred Credits and Other Liabilities Accumulated deferred income taxes (Notes 1 and 6). . . . . . . . . 275,814 281,560 Investment tax credit, in process of amortization. . . . . . . . . 88,779 91,572 Accumulated provision for pensions and related benefits. . . . . . 49,104 31,536 Customers' advances for construction . . . . . . . . . . . . . . . 8,621 7,384 Regulatory liability (Note 2). . . . . . . . . . . . . . . . . . . 8,914 6,876 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,047 10,910 --------- --------- 448,279 429,838 --------- --------- Commitments and Contingencies (Notes 10 and 11) $ 1,966,590 $ 1,974,584 --------- --------- --------- ---------
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 ------------------------------------------ 1994 1993 1992 ---- ---- ---- Cash Flows from Operating Activities Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 58,320 $ 90,535 $ 73,793 Items not requiring cash currently: Cumulative effect of change in accounting principle. . . . . . . . . 3,369 - - Non-recurring charges. . . . . . . . . . . . . . . . . . . . . . . . 38,613 - - Depreciation and amortization. . . . . . . . . . . . . . . . . . . . 82,519 79,887 79,686 Deferred income taxes - net. . . . . . . . . . . . . . . . . . . . . (2,274) 4,938 28,911 Investment tax credit - net. . . . . . . . . . . . . . . . . . . . . (4,619) (7,821) (5,033) Gain on sale of capital asset. . . . . . . . . . . . . . . . . . . . - (3,869) - Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,603 5,877 3,768 (Increase) decrease in certain net current assets: Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . 18,339 (11,678) (7,494) Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . 3,280 10,671 (8,014) Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . (22,781) 21,099 4,546 Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,247) 2,343 1,967 Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . 530 757 (1,716) Prepayments and other. . . . . . . . . . . . . . . . . . . . . . . . (743) (260) 538 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 972 (15,587) (11,321) ------- ------- ------- Net cash provided from operating activities. . . . . . . . . . . . . 180,881 176,892 159,631 ------- ------- ------- Cash Flows from Investing Activities Sale of capital asset. . . . . . . . . . . . . . . . . . . . . . . . . - 91,076 - Purchase of securities . . . . . . . . . . . . . . . . . . . . . . . . (87,896) (38,398) (26,677) Proceeds from sales of securities. . . . . . . . . . . . . . . . . . . 56,085 27,301 16,236 Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . (95,398) (98,787) (101,175) -------- ------- ------- Net cash used for investing activities . . . . . . . . . . . . . . . (127,209) (18,808) (111,616) -------- ------- ------- Cash Flows from Financing Activities Issuance of preferred stock. . . . . . . . . . . . . . . . . . . . . . - 24,716 49,099 Issuance of first mortgage bonds and pollution control bonds . . . . . - 198,918 88,462 Redemption of preferred stock. . . . . . . . . . . . . . . . . . . . . - (25,558) (51,443) Retirement of first mortgage bonds and pollution control bonds . . . . - (231,876) (92,400) Repayment of short-term borrowings . . . . . . . . . . . . . . . . . . - (8,000) (4,000) Payment of dividends . . . . . . . . . . . . . . . . . . . . . . . . . (58,639) (73,125) (74,517) ------- ------- -------- Net cash used for financing activities . . . . . . . . . . . . . . . (58,639) (114,925) (84,799) ------ ------- ------ Net (Decrease) Increase in Cash and Temporary Cash Investments . . . . . (4,967) 43,159 (36,784) Cash and Temporary Cash Investments at Beginning of Year . . . . . . . . 44,105 946 37,730 ------ ------ ------ Cash and Temporary Cash Investments at End of Year . . . . . . . . . . . $ 39,138 $ 44,105 $ 946 ------ ------- ------- ------ ------- ------- Supplemental Disclosures of Cash Flow Information Cash paid during the year for: Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 42,803 $ 54,686 $ 19,741 Interest on borrowed money . . . . . . . . . . . . . . . . . . . . . 40,827 45,360 50,508
The accompanying notes are an integral part of these financial statements. -25- LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Thousands of $)
December 31 ------------------------------------------ 1994 1993 ---- ---- 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 loss on marketable securities, net of income taxes of $1,434 (Note 4) . . . . . . . . . . . . . . . . . . . . . . . . (1,751) - Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193,895 194,903 -------- -------- $ 616,478 $ 619,237 -------- -------- 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 7.45% series . . . . . . . . . . . . 858,128 25.75 21,453 21,453 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. . . . . . . . . . . . . . . . . . . . . . . . . . . (1,244) (1,244) --------- --------- $ 116,716 $ 116,716 --------- --------- Long-Term Debt (Note 8) First mortgage bonds - Series due June 1, 1996, 5 5/8%. . . . . . . . . . . . . . . . . . . . . $ 16,000 $ 16,000 Series due June 1, 1998, 6 3/4%. . . . . . . . . . . . . . . . . . . . . 20,000 20,000 Series due July 1, 2002, 7 1/2%. . . . . . . . . . . . . . . . . . . . . 20,000 20,000 Series due August 15, 2003, 6% . . . . . . . . . . . . . . . . . . . . . 42,600 42,600 Pollution control series: J due July 1, 2015, 9 1/4% . . . . . . . . . . . . . . . . . . . . . . 40,000 40,000 K due December 1, 2016, 7 1/4% . . . . . . . . . . . . . . . . . . . . 27,500 27,500 L due December 1, 2016, 7 1/4% . . . . . . . . . . . . . . . . . . . . 22,500 22,500 N due February 1, 2019, 7 3/4% . . . . . . . . . . . . . . . . . . . . 35,000 35,000 O due February 1, 2019, 7 3/4% . . . . . . . . . . . . . . . . . . . . 35,000 35,000 P due June 15, 2015, 7.45% . . . . . . . . . . . . . . . . . . . . . . 25,000 25,000 Q due November 1, 2020, 7 5/8% . . . . . . . . . . . . . . . . . . . . 83,335 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 -------- -------- Total bonds outstanding. . . . . . . . . . . . . . . . . . . . . . . . . 662,800 662,800 Unamortized premium on bonds . . . . . . . . . . . . . . . . . . . . . . . 62 79 -------- -------- $ 662,862 $ 662,879 -------- -------- Total Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,396,056 $ 1,398,832 --------- --------- --------- ---------
The accompanying notes are an integral part of these financial statements. -26- LOUISVILLE GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Louisville Gas and Electric Company (the Company) completed a corporate restructuring on August 17, 1990, pursuant to which the Company became the primary subsidiary of LG&E Energy Corp. The Company is a regulated public utility that is engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas. LG&E Energy Corp. is an exempt energy services holding company with wholly owned subsidiaries consisting of the Company and LG&E Energy Systems Inc., a non-regulated subsidiary. All of the Company's Common Stock is held by LG&E Energy Corp. Certain reclassifications have been made to the 1993 and 1992 financial statements to conform with the 1994 presentation with no impact on previously reported income. UTILITY PLANT. The Company's plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base, and, accordingly, the Company has not recorded any allowance for funds used during construction. The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost plus removal expense less salvage value is charged to the reserve for depreciation. When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized. DEPRECIATION. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for 1994 were 3.3% (3.2% electric, 3.3% gas, and 5% common); for 1993 3.3% (3.2% electric, 3.2% gas, and 5% common); and for 1992, 3.3% (3.2% electric, 3.2% gas, and 5.4% common) of average depreciable plant. CASH AND TEMPORARY CASH INVESTMENTS. The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value. DEFERRED INCOME TAXES. Deferred income taxes have been provided for all book-tax temporary differences. -27- The Company adopted Statement of Financial Accounting Standards No. 109, ACCOUNTING FOR INCOME TAXES (SFAS No. 109), effective January 1, 1993. Regulatory assets and liabilities have been established to recognize the future revenue requirement impact from the deferred income taxes which were not immediately recognized in operating results because of ratemaking treatment. The adoption of SFAS No. 109 did not have a material impact on the results of operations or financial position. INVESTMENT TAX CREDITS. Investment tax credits resulted from provisions of the tax law that permitted a reduction of the Company's tax liability based on credits for certain construction expenditures. Investment tax credits deferred and charged to income in prior years are being amortized to income over the estimated lives of the related property that gave rise to the credits. DEBT PREMIUM AND EXPENSE. Debt premium and expense are amortized over the lives of the related debt issues, consistent with regulatory practices. REVENUE RECOGNITION. Revenues are recorded based on service rendered to customers through month end. The Company accrues an estimate for unbilled revenues from the date of each meter reading date to the end of the accounting period. Effective January 1, 1994, under an agreement approved by the Public Service Commission of Kentucky (Kentucky Commission or Commission), the Company implemented a demand side management program and a "decoupling mechanism," which allows the Company to recover a predetermined level of revenue on electric and gas residential sales. See Management's Discussion and Analysis, Rates and Regulation, under Item 7 for further discussion. FUEL AND GAS COSTS. The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system. INTEREST RATE CONTRACTS. Interest rate swaps are used by the Company to convert variable rate debt to a fixed rate. The cost or benefit of the interest rate swaps is recorded as a component of interest expense. REVENUES AND CUSTOMER RECEIVABLES. The Company is an operating public utility that supplies natural gas to approximately 266,000 customers and electricity to approximately 341,000 customers in Louisville and adjacent areas in Kentucky. Customer receivables and gas and electric revenues arise from deliveries of natural gas and electric energy to a diversified base of residential, commercial and industrial customers and to public authorities and other utilities. For the year ended December 31, 1994, 74% of total operating revenue was derived from electric operations and 26% from gas operations. NOTE 2 - RATES AND REGULATORY MATTERS The Company conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by the Federal Energy Regulatory Commission (FERC) and the Kentucky Commission. The Company is subject to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71). -28- 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 $):
1994 1993 ---- ---- Unamortized loss on bonds . . . . . . . $15,704 $16,622 Unamortized extraordinary retirements . 9,752 12,540 Post-retirement benefits. . . . . . . . - 1,200 Early retirement/workforce reduction. . - 17,617 Property damage settlements . . . . . . - 9,817 Manufactured gas sites. . . . . . . . . 3,149 926 Other . . . . . . . . . . . . . . . . . 3,121 2,920 Deferred income taxes - net . . . . . . (8,914) (6,876) ------ ------ Regulatory assets and liabilities - net $22,812 $54,766 ------ ------ ------ ------
As of December 31, 1994, approximately $15 million of the Company's net regulatory assets are being recovered through rates charged to customers over periods ranging from three to 22 years. The Company expects to obtain recovery of the remaining regulatory assets in its next general rate case. For additional information regarding post-retirement benefits and early retirement/workforce reduction costs, deferred income taxes, and environmental costs, see Notes 5, 6, and 10, respectively. In early 1994, the Company, based on a re-evaluation of its regulatory strategy, wrote off certain regulatory assets included in the 1993 balance sheet. See Note 3, Non-Recurring Charges, for a further discussion. In October 1994, the Company filed an application with the Kentucky Commission to implement an environmental cost recovery surcharge. The surcharge will allow the Company to recover certain costs incurred to comply with federal, state, and local environmental requirements. If approved by the Commission, the surcharge will take effect in May 1995. See Management's Discussion and Analysis, Rates and Regulation, under Item 7 for a further discussion. NOTE 3 - NON-RECURRING CHARGES As part of a study of LG&E Energy Corp.'s business strategy and realignment during 1994, the Company re-evaluated its regulatory strategy which previously had been to seek full recovery of certain costs deferred in accordance with prior precedents established by the Commission. As a result of this re-evaluation, the Company wrote off certain expenses that had previously been deferred amounting to approximately $38.6 million before taxes. While the Company continues to believe that it could have reasonably expected to recover these costs in future rate proceedings before the Commission, the Company decided to deduct these expenses currently and not seek recovery for such expenses in future rates due to increasing competitive pressures and the existing and anticipated future economic conditions. The items written off include costs incurred in connection with early retirements and workforce reductions that occurred in 1992 and 1993 which consist primarily of separation payments, enhanced early retirement benefits, and health care benefits; costs associated with property damage claims pertaining to particulate -29- emissions from its Mill Creek electric generating plant which primarily consist of spotting on automobile finish and aluminum siding; and certain costs previously deferred resulting from adoption in January 1993 of Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS. In the first quarter of 1994, the Board of Directors of the Company approved the formation of a tax-exempt charitable foundation (Foundation) which will make charitable contributions to qualified persons and entities. In 1994, the Company recorded a pre-tax charge against income and made an irrevocable payment of $15 million to fund the Foundation. On June 6, 1994, the Internal Revenue Service issued a letter stating that it had determined the Foundation was exempt from Federal income tax under the Internal Revenue Code. NOTE 4 - MARKETABLE SECURITIES AND OTHER FINANCIAL INSTRUMENTS MARKETABLE SECURITIES. The Company adopted the provisions of Statement of Financial Accounting Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES, effective January 1, 1994. Accordingly, the Company's marketable securities have been determined to be "available-for-sale" and are stated at market value in the accompanying December 31, 1994, balance sheet. The available-for-sale category of investments results in the classification of unrealized gains and losses on investments in common equity, net of income taxes, until such gains and losses are realized, at which time they are recognized in earnings. Proceeds from sales of available-for-sale securities were $56,085,000, which resulted in realized gains of $1,557,000 and losses of $1,538,000, calculated using the specific identification method. The difference between amortized and unamortized cost basis of the Company's investments in marketable securities as of December 31, 1994, was immaterial. Approximate cost, fair value, and other required information about the Company's available-for-sale securities by major security type as of December 31, 1994, follows (in thousands of $):
Fixed Equity Income Total ------ ------ ----- Cost. . . . . . . . . . . . . . . . . . . . . . . . . . . $23,622 $29,701 $53,323 Unrealized gains. . . . . . . . . . . . . . . . . . . . . 41 - 41 Unrealized losses . . . . . . . . . . . . . . . . . . . . (2,399) (827) (3,226) ------ ------ ------ Fair values . . . . . . . . . . . . . . . . . . . . . . . $21,264 $28,874 $50,138 ------ ------ ------ ------ ------ ------ - --------------------------------------------------------------------------------------------------------------------- Fair Values: No maturity . . . . . . . . . . . . . . . . . . . . . . $20,415 $ - $20,415 Contractual maturities: Less than one year. . . . . . . . . . . . . . . . . . 849 2,519 3,368 One to five years . . . . . . . . . . . . . . . . . . - 16,968 16,968 Five to ten years . . . . . . . . . . . . . . . . . . - 1,958 1,958 Over ten years. . . . . . . . . . . . . . . . . . . . - 3,381 3,381 Not due at a single maturity date . . . . . . . . . . - 4,048 4,048 ------ ------ ------ Total fair values . . . . . . . . . . . . . . . . . . . $21,264 $28,874 $50,138 ------- ------ ------ ------- ------ ------
-30- The Company's available-for-sale securities above include approximately $.6 million market value ($18.5 million notional amount) of short futures on U.S. Treasury Notes and Bonds maturing March 1995. The Company uses such instruments to hedge a major portion of its preferred equity portfolio to substantially reduce price volatility of the securities due to interest rate changes. The Company does not maintain any margin accounts relative to its investment positions. The Company's available-for-sale securities are classified as Other Property and Investments in the accompanying 1994 balance sheet. FINANCIAL INSTRUMENTS. Pursuant to Statement of Financial Accounting Standards No. 107, DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS, the Company is required to disclose the fair value of financial instruments where practicable. The disclosure of such information does not purport to be a market valuation of the Company as a whole. The carrying amounts of cash, accounts receivable, notes payable, and accounts payable reflected on the balance sheets approximates the fair value of these instruments due to the short duration to maturity. The fair value for certain of the Company's investments and debt are estimated based on quoted market prices for those or similar instruments. Investments for which there are no quoted market prices are stated at cost because a reasonable estimate of fair value cannot be made without incurring excessive costs. The fair value of interest rate swaps is based on the quoted market price as provided by the financial institution which is the counterparty to the swap. The cost and estimated fair value of the Company's financial instruments as of December 31, 1994 and 1993, are as follows (in thousands of $):
1994 1993 --------------------- -------------------- Fair Fair Cost Value Cost Value ---- ----- ---- ----- Long-term investments: Practicable to estimate fair value. . . . . . . . . . $53,323 $50,138 $21,186 $21,538 Not practicable . . . . . . . . . . . . . . . . . . . 490 490 490 490 Preferred stock subject to mandatory redemption . . . . 25,000 22,125 25,000 24,750 Long-term debt. . . . . . . . . . . . . . . . . . . . . 662,800 648,697 662,800 706,078 Interest rate swaps . . . . . . . . . . . . . . . . . . - 965 - (896)
NOTE 5 - PENSION PLANS AND RETIREMENT BENEFITS PENSION PLANS. The Company has two non-contributory, defined-benefit pension plans, covering all eligible employees. Retirement benefits are based on the employee's years of service and compensation. The Company's policy is to fund annual actuarial costs, up to the maximum amount deductible for income tax purposes, as determined under the frozen entry age actuarial cost method. -31- In addition, the Company has a supplemental executive retirement plan that covers officers of the Company. The plan provides retirement benefits based on average earnings during the final three years prior to retirement, reduced by social security benefits, any pension benefits received from plans of prior employers, and by amounts received under the pension plans referred to above. Pension costs were $4,423,000 for 1994, $2,669,000 for 1993, and $2,598,000 for 1992, of which approximately $693,000, $425,000, and $241,000, respectively, were charged to construction. The components of periodic pension expense are shown below (in thousands of $):
1994 1993 1992 ---- ---- ---- Service cost-benefits earned during the period. . . . . . . . . . . $ 4,813 $ 4,516 $ 5,459 Interest cost on projected benefit obligation . . . . . . . . . . . 13,057 12,117 11,006 Actual return on plan assets. . . . . . . . . . . . . . . . . . . . (489) (13,602) (8,850) Amortization of transition asset. . . . . . . . . . . . . . . . . . (1,112) (1,112) (1,076) Net amortization and deferral . . . . . . . . . . . . . . . . . . . (11,846) 750 (3,941) ------ ------ ------ Net pension cost. . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,423 $ 2,669 $ 2,598 ------ ------ ------ ------ ------ ------
The assets of the plans consist primarily of common stocks, corporate bonds, United States government securities, and interests in a pooled real estate investment fund. The funded status of the pension plans at December 31 is shown below (in thousands of $):
1994 1993 Actuarial present value of accumulated plan benefits: Vested. . . . . . . . . . . . . . . . . . . . . . . . . . . . $132,260 $137,655 Non-Vested. . . . . . . . . . . . . . . . . . . . . . . . . . 14,023 17,158 ------- ------- Accumulated benefit obligation. . . . . . . . . . . . . . . . 146,283 154,813 Effect of projected future compensation . . . . . . . . . . . 18,473 25,234 ------- ------- Projected benefit obligation. . . . . . . . . . . . . . . . . 164,756 180,047 Plan assets at fair value . . . . . . . . . . . . . . . . . . 159,638 165,088 ------- ------- Plan assets less than projected benefit obligation. . . . . . (5,118) (14,959) Unrecognized net transition asset . . . . . . . . . . . . . . (12,524) (13,636) Unrecognized prior service cost . . . . . . . . . . . . . . . 24,257 28,671 Unrecognized net gain . . . . . . . . . . . . . . . . . . . . (36,266) (23,860) ------- ------- Accrued pension liability . . . . . . . . . . . . . . . . . $(29,651) $(23,784) ------- ------- ------- -------
The projected benefit obligation was determined using an assumed discount rate of 8.5% for 1994 and 7.5% for 1993. An assumed annual rate of increase in future compensation levels ranged from 4.5% to 5% for 1994 and 3.5% to 4.5% for 1993. The assumed long-term rate of return on plan assets was 8.5% for 1994 and 1993. Transition assets and prior service costs are being amortized over the average remaining service period of active participants. -32- POST-RETIREMENT BENEFITS. The Company adopted Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS (SFAS No. 106), effective January 1, 1993. SFAS No. 106 requires the accrual of the expected cost of retiree benefits other than pensions during the employee's years of service with the Company. The Company is amortizing the discounted present value of the post-retirement benefit obligation at the date of adoption over 20 years. The Company provides certain health care and life insurance benefits for eligible retired employees. Post-retirement health care benefits are subject to a maximum amount payable by the Company. Prior to January 1, 1993, the cost of retiree health care and life insurance benefits was generally recognized when paid. This cost was $1,078,000 for 1992. In 1993, the Company began to account for post-retirement benefits according to the provisions of SFAS No. 106. In 1993, the Company, based on an order from the Commission, created a regulatory asset and deferred the level of SFAS No. 106 expense in excess of the previous level of pay-as-you-go expense. Therefore, the adoption of SFAS No. 106 did not have an effect on results of operations in 1993. However, in the first quarter of 1994, the Company began recognizing the excess SFAS No. 106 expense currently, including the amount previously deferred. See Note 3, Non-Recurring Charges. The components of the net periodic post-retirement benefit cost as calculated under SFAS No. 106 are as follows (in thousands of $):
1994 1993 ---- ---- Service cost . . . . . . . . . . . . . . . . $ 621 $ 701 Interest cost. . . . . . . . . . . . . . . . 2,386 2,614 Amortization of transition obligation. . . . 1,337 1,395 ----- ----- Post-retirement benefit cost $4,344 $4,710 ----- ----- ----- -----
The accumulated post-retirement benefit obligation as calculated under SFAS No. 106 at December 31, is shown below (in thousands of $):
1994 1993 ---- ---- Retirees . . . . . . . . . . . . . . . . . .$(18,487) $(17,826) Fully eligible active employees. . . . . . . (1,927) (4,001) Other active employees . . . . . . . . . . . (9,789) (15,945) ------- ------- Accumulated post-retirement benefit obligation . . . . . . . . . . . . . . . . . (30,203) (37,772) Unrecognized net (gain) loss . . . . . . . . (3,275) 4,966 Unrecognized transition obligation . . . . . 24,064 26,508 Previously recognized amount . . . . . . . . - 3,696 ------ ------- Accrued post-retirement benefit liability. .$ (9,414) $ (2,602) ------ ------- ------ -------
-33- The accumulated post-retirement benefit obligation was determined using an assumed discount rate of 8.5% for 1994 and 7.5% for 1993. Assumed compensation increases for projected life insurance benefits for affected groups was 5% for 1994 and 4.5% for 1993. An assumed health care cost trend rate of 10.5% was assumed for 1994, gradually decreasing to 5.25% in ten years and thereafter. A 1% increase in the assumed health care cost trend rate would increase the accumulated post-retirement benefit obligation by approximately $1 million and the annual service and interest cost by approximately $100,000. No funding has been established by the Company for post-retirement benefits. POST-EMPLOYMENT BENEFITS. The Company adopted Statement of Financial Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS (SFAS No. 112) on January 1, 1994, as required. SFAS No. 112 requires the accrual of the expected cost of benefits to former or inactive employees after employment but before retirement. The cumulative effect of the accounting change was recorded in the first quarter of 1994 and decreased net income by $3.4 million. EARLY RETIREMENT/WORKFORCE REDUCTION. During the last quarter of 1993, the Company eliminated approximately 350 full-time positions. The cost of the employee reduction program was approximately $11.5 million, and consisted primarily of separation payments, enhanced early retirement benefits, and health care benefits. In 1992, an early retirement program was made available to all Company union employees who had reached age 55, or who had 35 years or more of continuous service regardless of age. The cost of the program was approximately $7 million and consisted primarily of enhanced early retirement and health care benefits. THRIFT SAVINGS PLAN. The Company has a Thrift Savings Plan under Section 401(k) of the Internal Revenue Code. The plan covers all regular full-time employees with one year or more of service at the Company. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. The Company makes contributions to the plan by matching a portion of employee contributions according to a formula established by the plan. These costs were approximately $1,701,000 for 1994, $1,795,000 for 1993, and $767,000 for 1992. The increase in 1993 401(k) expenses over 1992 is due to the expansion of the program to the Company's union employees. -34- NOTE 6 - FEDERAL AND STATE INCOME TAXES Components of income tax expense are shown in the table below (in thousands of $):
1994 1993 1992 ---- ---- ---- Included in Operating: Current - Federal. . . . . . . . . . $35,552 $31,082 $20,756 - State. . . . . . . . . . . 9,003 8,920 6,354 Deferred - Federal-net. . . . . . . . (969) 13,185 15,771 - State-net. . . . . . . . . 955 3,933 5,774 Amortization of investment tax credit (4,619) (4,786) (4,815) ------- ------- ------ Total . . . . . . . . . . . $39,922 $52,334 $43,840 ------- ------- ------- Included in Other Income and (Deductions): Current - Federal . . . . . . . . . . $(4,626) $11,009 $(6,971) - State. . . . . . . . . . . (1,277) 4,034 (3,214) Deferred - Federal-net. . . . . . . . 19 (8,473) 4,670 - State-net. . . . . . . . . 1 (3,707) 2,696 Deferred investment tax credit. . . . - - 390 Amortization of investment tax credit - (3,035) (608) ------- ------- ------- Total . . . . . . . . . . .$ (5,883) $ (172) $(3,037) ------- ------- ------- Included in Cumulative Effect of a Change in Accounting for Post-Employment Benefits: Deferred - Federal. . . . . . . . . .$ (1,814) $ - $ - - State. . . . . . . . . . . (466) - - ------- ------ ------ Total. . . . . . . . . . . . . .$ (2,280) $ - $ - ------- ------ ------ Total Income Tax Expense. . . . . . . .$ 31,759 $52,162 $40,803 ------- ------ ------ ------- ------ ------
Variations in income tax expense are largely attributable to changes in pre-tax income. Provisions for deferred income taxes-net consist of the tax effects of the following temporary differences (in thousands of $):
1994 1993 1992 ---- ---- ---- Depreciation and amortization $12,609 $ (255) $33,839 Alternative minimum tax. . . - 5,387 (5,387) Pension overfunding. . . . . (4,357) (823) (900) Accrued liabilities not currently deductible . . . . (5,343) 1,210 295 Change in accounting principle (2,280) - - Other . . . . . . . . . . (2,903) (581) 1,064 ------ ------ ------- Total . . . . . . . . . . $(2,274) $4,938 $28,911 ------ ------ ------- ------ ------ -------
The net provisions for deferred income taxes decreased in 1994 due largely to recording certain liabilities which are not deductible until such liabilities are paid. Deferred income taxes attributable to depreciation and amortization decreased in 1993 because of the reversal of prior years' accumulated taxes as a result of the sale of a portion of Trimble County Unit 1. See Note 12, Jointly Owned Electric Utility Plant for a further discussion of the sale. -35- Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
December 31 January 31 1994 1993 1993 ---- ---- ---- Deferred Tax Liabilities: Depreciation and other plant related items. . $334,252 $322,544 $326,527 Income taxes due from customers . . . . . . 10,179 10,233 14,608 Other liabilities . . . 7,977 7,458 5,548 ------- ------- ------- $352,408 $340,235 $346,683 ------- ------- ------- Deferred Tax Assets: Investment tax credit . $ 35,833 $ 36,961 $ 42,229 Income taxes due to customers . . . . . . 13,942 14,361 15,477 Pension overfunding . . 11,145 6,781 5,951 Other assets. . . . . . 15,674 572 5,066 ------- ------- ------- $ 76,594 $ 58,675 $ 68,723 ------- ------- ------- Net deferred income tax liability. . . . . . $275,814 $281,560 $277,960 ------- ------- ------- ------- ------- -------
The Company's effective income tax rate is computed by dividing the aggregate of current income taxes, deferred income taxes-net, and the amortization of investment tax credit, by net income before the deduction of such taxes. Reconciliation of the statutory Federal income tax rate to the effective income tax rate is shown in the table below:
1994 1993 1992 ---- ---- ---- Statutory Federal income tax rate . . . 35.0% 35.0% 34.0% State income taxes net of Federal benefit 5.9 6.0 6.7 Investment tax credits. . . . . . . . . (5.1) (5.5) (4.7) Other differences-net . . . . . . . . . (.5) 1.1 (.4) ---- ---- ---- Effective Income Tax Rate . . . . . . . 35.3% 36.6% 35.6% ---- ---- ---- ---- ---- ----
NOTE 7 - OTHER INCOME AND (DEDUCTIONS) Other income and (deductions) consisted of the following at December 31 (in thousands of $):
1994 1993 1992 ---- ---- ---- Interest and dividend income . . . . . . . . . . $ 4,568 $ 3,112 $ 1,980 Gains (losses) on fixed asset disposal . . . . . 1,427 (3,523) 608 Gain on sale of 12.88% portion of Trimble County - 3,869 - Donations . . . . . . . . . . . . . . . . . (1,015) (909) (652) Income taxes and other . . . . . . . . . . . . . (2,529) (636) (4,139) ------ ------ ------ Total . . . . . . . . . . . . . . . . . $ 2,451 $ 1,913 $(2,203) ------ ------ ------ ------ ------ ------
NOTE 8 - FIRST MORTGAGE BONDS Annual requirements for the sinking funds of the Company's First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with the Pollution Control Bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166 2/3% of principal amounts of bonds otherwise -36- required to be so redeemed) have been applied in lieu of cash. It is the intent of the Company to apply property additions to meet 1995 sinking fund requirements of the First Mortgage Bonds. The trust indenture securing the First Mortgage Bonds constitutes a direct first mortgage lien upon substantially all property owned by the Company. The indenture, as supplemented, provides in substance that, under certain specified conditions, portions of retained earnings will not be available for the payment of dividends on common stock. No portion of retained earnings is presently restricted by this provision. Pollution Control Bonds (Louisville Gas and Electric Company Projects) issued by Jefferson and Trimble Counties, Kentucky, are secured by the assignment of loan payments by the Company to the Counties pursuant to loan agreements, and further secured by the delivery from time to time of an equal amount of the Company's First Mortgage Bonds, Pollution Control Series. First Mortgage Bonds so delivered are summarized in the Statements of Capitalization. No principal or interest on these First Mortgage Bonds is payable unless default on the loan agreements occurs. The interest rate reflected in the Statements of Capitalization applies to the Pollution Control Bonds. In March 1993, due to the sale of 12.88% of Trimble County Unit 1, the Company completed the defeasance of $25 million of its Pollution Control Bonds ($16.665 million of the 7.625% Series and $8.335 million of the 6.55% Series). The Company issued several series of lower interest bearing First Mortgage and Pollution Control Bonds in 1993 to refinance bonds with higher interest rates. In August 1993, the Company issued two separate series of Pollution Control Bonds (a $35.2 million, Variable Rate Series, which had an average interest rate of 3.740% at December 31, 1994, and 2.586% at December 31, 1993, and a $102 million, 5.625% Series) and redeemed five series of Pollution Control Bonds totaling $137.2 million with interest rates ranging from 6.125% to 6.7%. In August 1993, the Company also issued $42.6 million of 6% First Mortgage Bonds and redeemed two series of First Mortgage Bonds ($19.7 million at 8.25% and $21.362 million at 8.5%). In November 1993, the Company issued $26 million of Pollution Control Bonds, 5.45% Series and redeemed the $26 million, 9.75% Series. The Company entered into an agreement in November 1993 with Goldman, Sachs & Co. to issue $40 million of tax-exempt Pollution Control Bonds in 1995 at a rate of 5.9%. The issuance of the bonds in 1995 is subject to certain conditions. If issued, the proceeds will be used to redeem, in 1995, the outstanding 9.25% series of Pollution Control Bonds due July 1, 2015. The Company has outstanding interest rate swap agreements totaling $30 million. Under the agreements, which were entered into in 1992, the Company pays a fixed rate of 4.35% on $15 million for a five-year period and 4.74% on $15 million for a seven-year period. In return, the Company receives a floating rate based on the weighted average JJ Kenny index. The JJ Kenny index is a tax-exempt municipal bond interest rate index. These swaps were entered into as a standard hedging device in connection with the issuance of the Series S Pollution Control Bonds due September 1, 2017. The swaps are designed to reduce the Company's exposure to interest rate risk. The Company received interest at composite rates of 2.84%, 2.38%, and 2.73% in -37- 1994, 1993, and 1992, respectively and paid interest at a composite rate of 4.55% pursuant to the swaps. The Company's First Mortgage Bonds, 5.625% Series of $16 million is scheduled to mature in 1996 and the 6.75% Series of $20 million is scheduled to mature in 1998. There are no scheduled maturities of Pollution Control Bonds for the five years subsequent to December 31, 1994. The Company has no cash sinking fund requirements. NOTE 9 - NOTES PAYABLE The Company had no notes payable at December 31, 1994, or December 31, 1993. At December 31, 1994, the Company had unused lines of credit of $145 million, for which it pays commitment fees. The credit lines are scheduled to expire at various periods throughout 1995 and 1996. Management intends to renegotiate these lines when they expire. NOTE 10 - COMMITMENTS AND CONTINGENCIES CONSTRUCTION PROGRAM. The Company had commitments, primarily in connection with its construction program, aggregating approximately $8 million at December 31, 1994. Construction expenditures for the calendar years 1995 and 1996 are estimated to total approximately $200 million. FERC ORDER NO. 636. In 1994, the Company experienced its first full year operating under Order No. 636. Whereas the Company had previously purchased natural gas and pipeline transportation services from Texas Gas Transmission Corporation (Texas Gas), the Company now purchases only transportation services from Texas Gas and purchases natural gas from other sources. Under Order No. 636 pipelines may recover costs associated with the transition to and implementation of this order from pipeline customers, including the Company. The Commission issued an order, based on proceedings that were held to investigate the impact of Order No. 636 on utilities and ratepayers in Kentucky, providing that transition costs assessed on utilities by the pipelines, which are clearly identifiable as being related to the cost of the commodity itself, are appropriate to be recovered from customers through the gas supply clause. During 1994, the Company paid and began recovering from its customers approximately $2.8 million in transition costs. It is estimated that $6 million to $8 million in additional transition costs will be incurred by the Company during 1995, and these costs are also expected to be recovered from customers. The Company is a party to proceedings before FERC which will determine a number of pipeline transition issues. Because of the impact such issues may have on future costs, management is unable to estimate the level of transition costs, if any, for years subsequent to 1995. -38- OPERATING LEASE. The Company has an operating lease for its corporate office building that is scheduled to expire in June 2005. Total expense in connection with this lease for 1994, 1993, and 1992 was $2,192,000, $2,436,000, and $2,478,000, respectively. The future minimum annual lease payments under the lease agreement for years subsequent to December 31, 1994, are as follows (in thousands of $): 1995. . . . . . . . . . . . . $ 2,499 1996. . . . . . . . . . . . . 2,850 1997. . . . . . . . . . . . . 2,850 1998. . . . . . . . . . . . . 2,850 1999. . . . . . . . . . . . . 2,850 Thereafter. . . . . . . . . . 18,960 ------- Total . . . . . . . . . . $ 32,859 ------- ------- ENVIRONMENTAL. The Clean Air Act Amendments of 1990 impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. The legislation is extremely complex and its effect will substantially depend on regulations issued by the U.S. Environmental Protection Agency (USEPA). The Company is closely monitoring the continuing rule-making process in order to assess the precise impact of the legislation on the Company. All of the Company's coal-fired boilers are equipped with sulfur dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates required by the year 2000 under the legislation. However, as part of its ongoing capital construction program, the Company has spent $10 million to date and anticipates incurring additional capital expenditures of approximately $29 million through 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the legislation on the Company is expected to be minimal. The Company is well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities. In 1992, the Company entered two agreed orders with the Air Pollution Control District (APCD) of Jefferson County in which the Company committed to undertake remedial measures to address certain particulate emissions and alleged excess sulfur dioxide emissions from its Mill Creek electric generating plant. In May 1994, the Company completed all specified remedial measures in accordance with the terms of the agreed orders. The Company has agreed to commence a joint field sampling program with the APCD to demonstrate the effectiveness of the remedial measures. In August 1993, 34 persons filed a complaint in Jefferson Circuit Court against the Company seeking certification of a class consisting of all persons within 2.5 miles of the Mill Creek plant. The plaintiffs seek compensation for alleged personal injury and property damage attributable to emissions from the Mill Creek plant, injunctive relief, a fund to finance future medical monitoring of area residents, and other relief. In June 1994, the court denied the plaintiffs' motion for certification of the class and thus limited the scope of the litigation to the claims of the individual plaintiffs. The Company intends to vigorously defend itself in the pending litigation. In an effort to resolve property damage claims relating to particulate emissions from the Mill Creek plant, in July 1993, the Company commenced extensive negotiations and property damage settlements with adjacent residents who are not parties to the pending litigation. The negotiations and settlements are continuing and the Company currently estimates that property -39- damage claims for the particulate emissions should be settled for an aggregate amount of approximately $15 million. Accordingly, the Company has recorded an accrual of this amount. In response to a notification from the APCD that the Company's Cane Run plant may be the source of a potential exceedance of the National Ambient Air Quality Standards for sulfur dioxide, the Company submitted a draft action plan and modeling schedule to the APCD and USEPA. The APCD and USEPA have approved the submittals, and a Company contractor is currently conducting additional modeling activities. Although it is expected that corrective action will be accomplished through capital improvements, until the modeling activities are complete, the Company cannot determine the precise impact of this matter. In March 1994, the APCD adopted a regulation requiring a 15% reduction from 1990 volatile organic compound (VOC) emissions from industrial sources. There are currently no demonstrated technologies for control of VOC emissions from coal-fired boilers. Consequently, compliance with the regulation could require limits on generation at the Mill Creek and Cane Run plants, unless the APCD adopts a provision for compliance through utilization of banked emission allowances. The Company is currently negotiating with the APCD in an effort to demonstrate its eligibility for an exclusion from the VOC reduction requirements. The Company owns or formerly owned three primary sites where manufactured gas plant operations were located. Such manufactured gas plant operations, conducted in the 1838 to 1960 time period, typically produced coal tar byproducts and other constituents that may necessitate cleanup measures. The Company has completed an investigation of the level of contaminants present at the two company-owned sites, and the Company, along with the current owner of the third site and another party completed an investigation of the third site. Investigation and testing at these three sites has identified the presence of contaminants typical of manufactured gas operations. A report on the results of the investigation at each site has been prepared and submitted to the Kentucky Natural Resources and Environmental Protection Cabinet (KNREPC). The KNREPC will review the findings submitted by the Company, and through negotiations with the Company, the level of remediation required at each site will be determined. Although a precise determination of the costs associated with cleanup activities at these three sites cannot be made until the required level of remediation is established, management currently estimates that the total cost will fall within a range of $3 million to $12 million and has recorded an accrual of approximately $3 million in the accompanying financial statements. In November 1993, the Company was served with a third-party complaint filed in federal district court in Illinois by three third-party plaintiffs. The third-party plaintiffs allege that the Company and 31 other parties are liable under the Comprehensive Environmental Response, Compensation, and Liability Act as amended (CERCLA) for $1.4 million in costs allegedly incurred by USEPA in conducting cleanup activities at the M.T. Richards Site in Crossville, Illinois. A number of de minimis third party defendants, including the Company, have commenced settlement discussions with the third-party plaintiffs. In the Company's opinion, the resolution of this issue will not have a material adverse impact on its financial position or results of operations. In June 1992, USEPA identified the Company as a potentially responsible party (PRP) allegedly liable under CERCLA for $1.6 million in costs allegedly incurred by USEPA in cleanup of the Sonora Site and Carlie Middleton Burn Site located in Hardin County, Kentucky. The USEPA -40- has since increased the amount of its demand to $1.8 million to reflect additional cleanup costs. In September 1994, USEPA filed a CERCLA cost recovery action in U.S. District Court against the Company and six other parties. In the Company's opinion, the resolution of this issue will not have a material adverse impact on its financial position or results of operations. In 1987, USEPA identified the Company as one of the numerous PRPs allegedly liable under CERCLA for the Smith's Farm Site in Bullitt County, Kentucky. In March 1990, USEPA issued an administrative order requiring the Company and 35 other PRPs to conduct certain cleanup activities. In February 1992, four PRPs filed a complaint in federal district court in Kentucky against the Company and 52 other PRPs. Under the law, each PRP could be held jointly and severally liable for the cost of site cleanup, but would have the right to seek contribution from other PRPs. In July 1993, upon motion of the plaintiffs, the federal court dismissed the Company and a number of others from the litigation in order to facilitate settlement negotiations among the parties. Cleanup costs for the site are currently estimated at approximately $70 million. The Company and several other parties have shared certain cleanup costs in the interim until a voluntary allocation of liability can be reached among the parties. It is not possible at this time to predict the outcome or precise impact of this matter. However, management believes that this matter should not have a material adverse impact on the financial position or results of operations of the Company as other financially viable PRPs appear to have primary liability for the site. NOTE 11 - TRIMBLE COUNTY GENERATING PLANT Trimble County Unit 1 (Trimble County), a 495-megawatt, coal-fired electric generating unit placed into service in December 1990, is currently the subject of an administrative proceeding before the Commission. This proceeding, which originally began in 1988, was initiated by the Commission to determine the appropriate ratemaking treatment to implement its 1988 decision that the Company should not be allowed to recover 25% of the cost of the Unit from ratepayers. As a result of a non-unanimous settlement agreement in the initial 1989 proceedings reached between the Company and the Commission staff, which was approved by the Kentucky Commission in October 1989, the Company returned to its customers $11.1 million through refunds and rate reductions. The Commission's approval of the settlement agreement was appealed by certain intervenors in the case who had not joined in the agreement. In April 1993, the Kentucky Court of Appeals held that the Commission exceeded its authority in approving the agreement, and ordered the Commission to hold new hearings on the underlying issues. Pursuant to a Commission procedural order, the Company filed direct testimony on January 7, 1994, in which the Company recommended that the Commission allow it to recover the $11.1 million it refunded to customers under the 1989 settlement agreement. Testimony filed by intervenors recommended that the Commission order the Company to refund approximately $183 million, based upon their argument that the Company should refund 25% of the revenue requirements associated with Trimble County's construction-work-in-progress (CWIP) collected through rates over the course of the Trimble County construction project. On March 25, 1994, the Kentucky Attorney General and the Jefferson County Attorney filed a motion with the Commission in which they requested that two of the three members of the Commission and certain unspecified Commission staff employees be recused from further participation in the case. The intervenors supported the motion by arguing that past statements and orders of the Commission in this and other proceedings showed that the Commissioners had -41- prejudged the issues relevant to the current proceeding. The issues referred to in the motion centered on the intervenors' claims that the Company should refund 25% of all revenues associated with Trimble County CWIP collected through rates during the course of the plant's construction. On July 8, 1994, the Commission entered an order which denied the intervenors' motion. In the order, the Commission stated that it had not prejudged any issues but rather had decided a number of issues in past proceedings which are binding on it and all other parties. The Commission also stated that it had never implied in prior orders that the amounts of Trimble County CWIP included in rate base prior to the issuance of its July 1, 1988, order in Case No. 10064, a general rate case, would be subject to later review. The Commission concluded that the scope of the present case had been limited since at least 1985 when the Commission issued an order that put the Company on notice that in future rate cases the continuation of allowing a return on further additions to Trimble County CWIP would be an issue. The Company believes that the Commission's July 8 order makes it unlikely that the Commission will entertain the position that the intervenors have taken in their previously-filed testimony that the Company refund approximately $183 million to its customers. The Company believes that remaining at issue is what amount, if any, of the approximately $30 million it collected subject to refund under a rate case order issued in 1988 should be returned to ratepayers. As discussed previously, approximately $11.1 million has already been returned to ratepayers under the 1989 settlement agreement. However, the Company is unable to predict the outcome of the Commission proceedings, or the amount of additional refunds or recoveries, if any, that may be ordered. The Commission has set May 9, 1995, as the formal hearing date in the Trimble County proceedings. The purpose of the hearing is to determine the proper ratemaking treatment to exclude 25% of Trimble County from customer rates for the period from May 1988 to December 31, 1990. The Company's current rates, which became effective January 1, 1991, reflect the disallowance of 25% of the plant. Reference is made to Note 12, Jointly Owned Electric Utility Plant, for a discussion of the sale of 25% of Trimble County. NOTE 12 - JOINTLY OWNED ELECTRIC UTILITY PLANT The Company owns a 75% undivided interest in Trimble County Unit 1. Accounting for the 75% portion of the Unit, which the Commission has allowed to be reflected in customer rates, is similar to the Company's accounting for other wholly owned utility plants. Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA) purchased a 12.12% undivided interest in the Unit on February 28, 1991, and Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided interest on February 1, 1993. Each is responsible for their proportionate ownership share of operation and maintenance expenses and incremental assets, and for fuel used. -42- The following data represent shares of the jointly owned property:
Trimble County ---------------------------------- LG&E IMPA IMEA Total ---- ---- ---- ----- Ownership interest . . . 75% 12.88% 12.12% 100% Mw capacity. . . . . . . 371.25 63.75 60 495
NOTE 13 - SEGMENTS OF BUSINESS The Company is an operating public utility engaged in the generation, transmission, distribution, and sale of electricity and the transmission, distribution, and sale of natural gas.
1994 1993 1992 ---- ---- ---- (Thousands of $) Operating Information Operating Revenues Electric. . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669 Gas . . . . . . . . . . . . . . 200,129 204,915 178,526 ------- ------- ------- Total . . . . . . . . . . . . $ 759,075 $ 775,125 $ 700,195 ------- ------- ------- ------- ------- ------- Pre-tax Operating Income Electric. . . . . . . . . . . . . $ 139,594 $ 171,016 $ 154,547 Gas . . . . . . . . . . . . . . . 11,368 17,436 15,122 ------- ------- ------- Total . . . . . . . . . . . . $ 150,962 $ 188,452 $ 169,669 ------- ------- ------- ------- ------- ------- Other Information Depreciation and Amortization Electric . . . . . . . . . . . . $ 71,882 $ 69,753 $ 67,869 Gas. . . . . . . . . . . . . . . 10,637 9,902 9,034 Non-Jurisdictional . . . . . . . - 232 2,783 ------- ------- -------- Total. . . . . . . . . . . . . $ 82,519 $ 79,887 $ 79,686 ------- ------- -------- ------- ------- -------- Construction Expenditures Electric. . . . . . . . . . . . . $ 71,592 $ 74,165 $ 75,630 Gas. . . . . . . . . . . . . . . 23,806 24,622 25,545 ------- ------- ------- Total. . . . . . . . . . . . . $ 95,398 $ 98,787 $ 101,175 ------- ------- ------- ------- ------- ------- Investment Information-December 31 Identifiable Assets Electric. . . . . . . . . . . . $1,514,287 $1,537,387 $1,528,123 Gas . . . . . . . . . . . . . . 252,946 241,930 222,958 --------- --------- --------- Total . . . . . . . . . . . . 1,767,233 1,779,317 1,751,081 Trimble County (a). . . . . . . . - - 87,794 Other Assets (b). . . . . . . . . 199,357 195,267 121,985 --------- --------- --------- Total Assets. . . . . . . . . $1,966,590 $1,974,584 $1,960,860 --------- --------- --------- --------- --------- --------- (a) Represents the portion of Trimble County not allowed in customer rates. (b) Includes cash and temporary cash investments, accounts receivable, unamortized debt expense, and other property and investments.
-43- REPORT OF MANAGEMENT The management of Louisville Gas and Electric Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report. These statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management. The Company's financial statements have been audited by Arthur Andersen LLP, independent public accountants. Management has made available to Arthur Andersen LLP all the Company's financial records and related data as well as the minutes of shareholders' and directors' meetings. Management has established and maintains a system of internal controls that provide reasonable assurance that transactions are completed in accordance with management's authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by the Company's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal auditors. These recommendations for the year ended December 31, 1994 did not identify any significant deficiencies in the design and operation of the Company's internal control structure. The Audit Committee of the Board of Directors is composed entirely of outside directors. In carrying out its oversight role for the financial reporting and internal controls of the Company, the Audit Committee meets regularly with the Company's independent public accountants, internal auditors and management. The Audit Committee reviews the results of the independent accountants' audit of the financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Audit Committee also approves the annual internal auditing program, and reviews the activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Audit Committee at any time. Louisville Gas and Electric Company maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure, and the confidentiality of proprietary information. -44- REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO LOUISVILLE GAS AND ELECTRIC COMPANY: We have audited the accompanying balance sheets and statements of capitalization of Louisville Gas and Electric Company (a Kentucky corporation and a wholly owned subsidiary of LG&E Energy Corp.) as of December 31, 1994 and 1993, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As further discussed in Note 11, the potential amount of future rate refunds that may be required, if any, once the outcome of the legal and regulatory process is known, is uncertain at this time. As discussed in Notes 1 and 5 to the financial statements, effective January 1, 1993, the Company changed its methods of accounting for income taxes and post-retirement benefits other than pensions, and effective January 1, 1994, the Company changed its method of accounting for post-employment benefits. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. Louisville, Kentucky, Arthur Andersen LLP January 30, 1995 -------------------------------- -45- SELECTED QUARTERLY FINANCIAL DATA (Unaudited) (Thousands of $) Selected financial data for the four quarters of 1994 and 1993 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
Quarters Ended ------------------------------------------------- March June September December ----- ---- --------- -------- 1994 Operating Revenues . . . . . $219,679 $173,042 $190,117 $176,237 Net Operating Income . . . . 6,603 29,873 45,913 28,651 Net Income (Loss). . . . . . (16,695) (a) 20,636 35,438 18,941 Net Income (Loss) Available for Common Stock . . . . . (18,073) (a) 19,256 33,935 17,374 1993 Operating Revenues . . . . . $208,631 $166,906 $200,408 $199,180 Net Operating Income . . . . 32,754 28,395 47,786 27,183 Net Income . . . . . . . 20,786 16,566 36,447 16,736 Net Income Available for Common Stock . . . . . . . 19,199 14,898 35,099 15,358 (a) See Note 3 of Notes to Financial Statements under Item 8.
------------------------------------- ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. -46- PART III ITEMS 10, 11, 12 AND 13 are omitted pursuant to General Instruction G, inasmuch as the Company filed copies of a definitive proxy statement with the Commission on March 16, 1995, pursuant to Regulation 14A under the Securities Exchange Act of 1934. Such proxy statement is incorporated herein by this reference. In accordance with General Instruction G of Form 10-K, the information required by Item 10 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, 1994, 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, 1994 (page 23). Statements of Retained Earnings for the three years ended December 31, 1994 (page 23). Balance Sheets - December 31, 1994, and 1993 (page 24). Statements of Cash Flows for the three years ended December 31, 1994 (page 25). Statements of Capitalization - December 31, 1994, and 1993 (page 26). Notes to Financial Statements (pages 27-43). Report of Management (page 44). Report of Independent Public Accountants (page 45). Selected Quarterly Financial Data for 1994 and 1993 (page 46). 2. Financial Statement Schedule (included in Part IV): Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 1994 (page 60). All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements. -47- 3. Exhibits: Exhibit No. Description ------- ----------- 3.01 Copy of Restated Articles of Incorporation, as amended. [Filed as Exhibit 3.01 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 3.02 Copy of Amendment to Articles of Incorporation, effective May 25, 1989. [Filed as Exhibit 3.02 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 3.03 Copy of Amendment to Articles of Incorporation, effective February 6, 1992. [Filed as Exhibit 3.03 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 3.04 Copy of Amendment to Articles of Incorporation, effective April 8, 1993. [Filed as Exhibit 3.04 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 3.05 Copy of Amendment to Articles of Incorporation, effective May 19, 1993. [Filed as Exhibit 3.05 to the Company's Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 3.06 Copy of Bylaws, as amended through May 13, 1993. [Filed as Exhibit 3.01 to the Company's Form 10-Q for the quarter ended June 30, 1993, and incorporated by reference herein] 4.01 Copy of Trust Indenture dated November 1, 1949, from the Company to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to Registration Statement 2-8283 and incorporated by reference herein] 4.02 Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.05 to Registration Statement 2-9371 and incorporated by reference herein] 4.03 Copy of Supplemental Indenture dated February 1, 1954, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.03 to Registration Statement 2-11923 and incorporated by reference herein] -48- 4.04 Copy of Supplemental Indenture dated September 1, 1957, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.04 to Registration Statement 2-17047 and incorporated by reference herein] 4.05 Copy of Supplemental Indenture dated October 1, 1960, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.05 to Registration Statement 2-24920 and incorporated by reference herein] 4.06 Copy of Supplemental Indenture dated June 1, 1966, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.06 to Registration Statement 2-28865 and incorporated by reference herein] 4.07 Copy of Supplemental Indenture dated June 1, 1968, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.07 to Registration Statement 2-37368 and incorporated by reference herein] 4.08 Copy of Supplemental Indenture dated June 1, 1970, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.08 to Registration Statement 2-37368 and incorporated by reference herein] 4.09 Copy of Supplemental Indenture dated August 1, 1971, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.09 to Registration Statement 2-44295 and incorporated by reference herein] 4.10 Copy of Supplemental Indenture dated June 1, 1972, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.10 to Registration Statement 2-52643 and incorporated by reference herein] 4.11 Copy of Supplemental Indenture dated February 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.11 to Registration Statement 2-57252 and incorporated by reference herein] 4.12 Copy of Supplemental Indenture dated September 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.12 to Registration Statement 2-57252 and incorporated by reference herein] 4.13 Copy of Supplemental Indenture dated September 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.13 to Registration Statement 2-57252 and incorporated by reference herein] -49- 4.14 Copy of Supplemental Indenture dated October 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.14 to Registration Statement 2-65271 and incorporated by reference herein] 4.15 Copy of Supplemental Indenture dated June 1, 1978, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.15 to Registration Statement 2-65271 and incorporated by reference herein] 4.16 Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.16 to Registration Statement 2-65271 and incorporated by reference herein] 4.17 Copy of Supplemental Indenture dated September 1, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein] 4.18 Copy of Supplemental Indenture dated September 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein] 4.19 Copy of Supplemental Indenture dated September 15, 1981, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 4.20 Copy of Supplemental Indenture dated March 1, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.20 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein] 4.21 Copy of Supplemental Indenture dated March 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein] 4.22 Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein] -50- 4.23 Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.23 to the Company's Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein] 4.24 Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein] 4.25 Copy of Supplemental Indenture dated November 15, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein] 4.26 Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein] 4.27 Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein] 4.28 Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein] 4.29 Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein] 4.30 Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein] 4.31 Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein] -51- 4.32 Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 4.33 Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 4.34 Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 4.35 Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 4.36 Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.01 Copy of Agreement dated September 1, 1970, between Texas Gas Transmission Corporation and the Company covering the purchase of natural gas. [Filed as Exhibit 4.01 to Registration Statement 2-40985 and incorporated by reference herein] 10.02 Copies of Agreement between Sponsoring Companies re: Project D of Atomic Energy Commission, dated May 12, 1952, Memorandums of Understanding between Sponsoring Companies re: Project D of Atomic Energy Commission, dated September 19, 1952 and October 28, 1952, and Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission, dated October 15, 1952. [Filed as Exhibit 13(y) to Registration Statement 2-9975 and incorporated by reference herein] 10.03 Copy of Modification No. 1 dated July 23, 1953, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4.03(b) to Registration Statement 2-24920 and incorporated by reference herein] -52- 10.04 Copy of Modification No. 2 dated March 15, 1964, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02c to Registration Statement 2-61607 and incorporated by reference herein] 10.05 Copy of Modification No. 3 and No. 4 dated May 12, 1966 and January 7, 1967, respectively, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibits 4(a)(13) and 4(a)(14) to Registration Statement 2-26063 and incorporated by reference herein] 10.06 Copy of Modification No. 5 dated August 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 13(c) to Registration Statement 2-27316 and incorporated by reference herein] 10.07 Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02f to Registration Statement 2-61607 and incorporated by reference herein] 10.08 Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to Registration Statement 2-26063 and incorporated by reference herein] 10.09 Copies of Amendments to Agreements (iii) and (iv) referred to under 10.07 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02h to Registration Statement 2-61607 and incorporated by reference herein] 10.10 Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02i to Registration Statement 2-61607 and incorporated by reference herein] -53- 10.11 Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02j to Registration Statement 2-6l607 and incorporated by reference herein] 10.12 Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to Registration Statement 2-26063 and incorporated by reference herein] 10.13 Copy of Modification No. 6 dated November 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4(g) to Registration Statement 2-28524 and incorporated by reference herein] 10.14 Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02m to Registration Statement 2-37368 and incorporated by reference herein] 10.15 Copy of Modification No. 7 dated November 5, 1975, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02n to Registration Statement 2-56357 and incorporated by reference herein] 10.16 Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02o to Registration Statement 2-56357 and incorporated by reference herein] 10.17 Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02p to Registration Statement 2-6l607 and incorporated by reference herein] 10.18 Copy of Modification No. 8 dated June 23, 1977, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02q to Registration Statement 2-61607 and incorporated by reference herein] 10.19 Copy of Modification No. 9 dated July 1, 1978, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02r to Registration Statement 2-63149 and incorporated by reference herein] -54- 10.20 Copy of Modification No. 10 dated August 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.21 Copy of Modification No. 11 dated September 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.22 Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.23 Copy of Modification No. 12 dated August 1, 1981, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 10.24 Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 10.25 Copy of Diversity Power Agreement dated September 9, 1987, between East Kentucky Power Cooperative and the Company covering the purchase and sale of power between the two companies from 1988 through 1995. [Filed as Exhibit 10.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein] 10.26 Copy of Supplemental Executive Retirement Plan as amended through January 3, 1990, covering all officers of the Company. [Filed as Exhibit 10.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein] 10.27 Copy of Omnibus Long-Term Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 4.01 to the Company's Registration Statement 33-38557 and incorporated by reference herein] -55- 10.28 Copy of Key Employee Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 10.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein] 10.29 Copy of LG&E Energy Corp. Deferred Stock Compensation Plan effective January 1, 1992, covering non-employee directors of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein] 10.30 Copy of form of change in control agreement for officers of Louisville Gas and Electric Company. [Filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.31 Copy of Supplemental Executive Retirement Plan for Roger W. Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.32 Copy of Nonqualified Savings Plan covering officers of the Company, effective January 1, 1992. [Filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.33 Copy of Modification No. 13 dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.34 Copy of Modification No. 14 dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.35 Copy of Modification No. 7 dated January 15, 1992, to Inter- Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] -56- 10.36 Copy of Modification No. 15 dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.37 Firm Transportation Agreement, dated November 1, 1993, between Texas Gas Transmission Corporation and the Company covering the transmission of natural gas. [Filed as Exhibit 10.46 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.38 Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (8-year term) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (2-year term) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and the Company (5-year term) covering the transmission of natural gas. [Filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.39 Employment Contract between LG&E Energy Corp. and Roger W. Hale effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.40 Copy of LG&E Energy Corp. Stock Option Plan for Non-Employee Directors. [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.41 Copy of Coal Supply Agreement dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. 10.42 Copy of Amendment No. 1 dated January 1, 1991, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal -57- Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. 10.43 Copy of Amendment No. 2 dated November 27, 1991, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. 10.44 Copy of Amendment No. 3 dated January 1, 1994, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. 10.45 Copy of Amendment No. 4 dated January 1, 1995, to Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. 10.46 Copy of Coal Supply Agreement dated January 1, 1994, between Peabody Coalsales Company and the Company covering the purchase of coal. 12 Computation of Ratio of Earnings to Fixed Charges 23 Consent of Independent Public Accountants 24 Power of Attorney 27 Financial Data Schedule (b) Executive Compensation Plans and Arrangements: Supplemental Executive Retirement Plan as amended through January 3, 1990, covering all officers of the Company. [Filed as Exhibit 10.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein] Omnibus Long-Term Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 4.01 to the Company's Registration Statement 33-38557 and incorporated by reference herein] Key Employee Incentive Plan effective January 1, 1990, covering officers and key employees of the Company. [Filed as Exhibit 10.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein] -58- LG&E Energy Corp. Deferred Stock Compensation Plan effective January 1, 1992, covering non-employee directors of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein] Form of change in control agreement for officers of Louisville Gas and Electric Company. [Filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] Supplemental Executive Retirement Plan for R. W. Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] Nonqualified Savings Plan covering officers of the Company effective January 1, 1992. [Filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] Employment Contract between LG&E Energy Corp. and Roger W. Hale effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] LG&E Energy Corp. Stock Option Plan for Non-Employee Directors. [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] (c) Reports on Form 8-K: The Company was not required to file a Form 8-K report during the fourth quarter of 1994. -59- SCHEDULE II LOUISVILLE GAS AND ELECTRIC COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 1994 (Thousands of $)
Reserves Deducted from Assets in Balance Sheet ------------------------------------ Other Accounts Property Receivable and (Uncollectible Investments Accounts) ----------- ------------- Balance January 1, 1992. . . . . . . $ 2,862 $ 1,413 Additions: Charged to costs and expenses Trimble County - non-jurisdictional depreciation . . . . . . 2,783 Other. . . . . . . . . . . 2,158 Deductions: Net charges of nature for which reserves were created. . . 2,462 ----- ----- Balance December 31, 1992. . . . . . 5,645 1,109 Additions: Charged to costs and expenses Trimble County - non-jurisdictional depreciation . . . . . . 233 Other. . . . . . . . . . . 2,500 Deductions: Net charges of nature for which reserves were created. . . 2,135 Other . . . . . . . . . . . 5,815 ----- ----- Balance December 31, 1993. . . . . . 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 ----- ----- ----- -----
-60- SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. LOUISVILLE GAS AND ELECTRIC COMPANY Registrant March 24, 1995 By - -------------- ------------------------------------------ (Date) M. L. Fowler Vice President and Controller Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. Signature Title Date --------- ----- ---- ROGER W. HALE Chairman of the Board and Chief Executive Officer (Principal Executive Officer); CHARLES A. MARKEL III Treasurer (Principal Financial Officer); M. L. FOWLER Vice President and Controller (Principal Accounting Officer); WILLIAM C. BALLARD, JR. Director; OWSLEY BROWN II Director; S. GORDON DABNEY Director; GENE P. GARDNER Director; J. DAVID GRISSOM Director; DAVID B. LEWIS Director; ANNE H. MCNAMARA Director; T. BALLARD MORTON, JR. Director; and DR. DONALD C. SWAIN Director. By__________________________________ March 24, 1995 M. L. FOWLER (Attorney-In-Fact) -61- EX-10.41 2 EXHIBIT 10.41 EXHIBIT 10.41 COAL SUPPLY AGREEMENT THIS COAL SUPPLY AGREEMENT ("Agreement") entered into this 9th day of August, 1989 by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation ("Buyer") and SHAWNEE COAL COMPANY, a Tennessee corporation, and ROBERTS BROS. COAL CO. INC., a Kentucky corporation (hereafter severally, collectively and jointly "Seller"). W I T N E S S E T H: WHEREAS, Buyer is an electric utility company which desires to purchase steam coal; and WHEREAS, Seller has access to various sources of such coal and desires to supply such coal to Buyer. NOW THEREFORE, in consideration of the mutual covenants contained herein, Seller agrees to sell and deliver and Buyer agrees to purchase and accept delivery of coal on the terms and conditions set forth herein. 1. TERM 1.1 TERM. Except for specific effective dates described in specific sections herein, the term of this Agreement shall commence on March 1, 1989 and shall continue until and including December 31, 1995. Buyer shall have the right, but not the obligation, to renew this Agreement for up to three (3) additional five (5) year periods, such right to be exercised by notice in writing to Seller no later than sixty (60) days prior to the end of the existing period. The Base Price upon any such renewal shall be agreed upon by the parties subject to the provisions of Section 6.2. 2. QUANTITY 2.1 ANNUAL QUANTITY. This section effective January 1, 1989. Except as adjusted under Section 2.3, Seller shall sell and deliver and Buyer shall purchase and accept delivery of the following annual tonnages ("Annual Quantity"). YEAR ANNUAL QUANTITY (TONS) 1989 364,000 1990 364,000 1991 500,000 1992 750,000 1993 750,000 1994 750,000 1995 750,000 2.2 RATE OF SHIPMENT. The Annual Quantity shall be shipped in accordance with a reasonable monthly delivery schedule supplied by Buyer to Seller as further provided in Section 2.3. Time is of the essence with respect to the schedule so established, and failure by Seller to deliver in timely fashion shall constitute a default within the meaning of Section 15 of this Agreement. 2.3 NOTIFICATION. By December 1 of each Agreement year, Buyer shall specify by written notice to Seller the monthly quantities to be delivered in the following Agreement year. Commencing on January 1, 1991, upon 6 months notice to Seller, Buyer may change the quantity to be delivered under this Section within a range of +/- 20% of specified annual tonnage, except that in no event shall Buyer specify less than 400,000 tons for the 1991 Agreement year, and 600,000 tons for Agreement years 1992 and following. Further, Buyer shall have the option to purchase up to an additional 168,000 tons per year for 1989 and 1990. 3. SOURCE AND DELIVERY 2 3.1 SOURCE. The coal sold hereunder, including coal purchased from third parties, shall be supplied from Western Kentucky geological seams Nos. 4, 6, 8, 9, 11, 12 and 13 or their equivalent in the opinion of Buyer. The source is described with particularity in Exhibit A "Coal Property" attached hereto and made a part hereof (hereafter "Coal Property"). The designated source of coal of the quality set forth in Section 4.1 (Standard Specifications) are the following mines: Cardinal Mine, Hopkins County, Kentucky; Oriole Mine, Hopkins County, Kentucky; Donaldson Creek Mine, Hopkins County, Kentucky; Diamond Mine, Webster County, Kentucky; Kohl Trust Mine, Hopkins County, Kentucky and such other reserves as Seller may procure over the life of this Agreement. Seller may provide coal from any combination of sources provided that the Standard Specifications under Section 4.1, in Buyer's sole reasonable judgment, are met or exceeded. Seller shall promptly notify Buyer of any such changes. In the event Buyer approves any source(s) with such different specifications, the price for such coal shall be determined as set forth in Section 3.4. 3.2 ASSURANCE OF OPERATION AND RESERVES. Seller represents and warrants that the Coal Property contains economically recoverable cost of a quality and in quantities which will be sufficient to satisfy all the requirements of this Agreement. Seller agrees and warrants that it will have at the Coal Property adequate machinery, equipment and other facilities to produce, prepare and deliver coal in the quantity and at the quality required by this Agreement. Seller further agrees to operate and maintain such machinery, equipment and facilities in accordance with good mining practices so as to efficiently and economically produce, prepare and deliver such coal. Seller agrees that Buyer is not providing any capital for the purchase of such machinery, equipment and/or facilities and that Seller shall operate and maintain same at its sole expense, including all required permits and licenses. Seller hereby dedicates to this Agreement sufficient 3 reserves of coal meeting the quality specifications hereof and lying on or in the Coal Property so as to fulfill the quantity requirements hereof. 3.3 NON-DIVERSION OF COAL. Seller agrees and warrants that it will not, without Buyer's express prior written consent, use or sell coal from the Coal Property in a way that will reduce the economically recoverable balance of coal in the Coal Property to an amount less than that required to be supplied to Buyer hereunder. 3.4 SUBSTITUTE COAL. Notwithstanding the above representations and warranties, in the event of Seller's inability to produce coal in the quantity and at the quality required by this Agreement, Seller may, with the express written consent of Buyer, and subject to any reasonable terms Buyer may require including, without limitation, the right to share equally in the savings realized by Seller, supply coal (in all respects of the same or better quality in Buyer's sole opinion as that provided from the Coal Property) from other facilities and mines; provided however that the fully evaluated price to Buyer of any such coal shall not be greater than said fully evaluated price in $/MMBTU would have been had the coal been supplied from the Coal Property ("fully evaluated price" as used in this Agreement shall mean the price of coal FOB rail car or barge, plus transportation, plus or minus, as applicable, quality adjustments, if any.) 3.5 RAIL DELIVERY. Buyer and Seller hereby select rail transportation on the Paducah & Louisville (PAL) Railway as the method of shipment for all coal under this Agreement. Title to and risk of loss of coal will pass to Buyer and the coal will be considered to be delivered when it is loaded into the railcars at the Cardinal Mine rail loading facility near Madisonville, Kentucky on the PAL railway. Buyer or its contractor shall furnish suitable railcars in accordance with a delivery schedule provided by Buyer to Seller. With Buyer's prior approval, Seller may deliver the coal to any rail loading facility ("Delivery Point"), provided, however, the total delivered cost 4 of the coal by train to Buyer's generating stations from any Delivery Point shall not exceed the total delivered cost of coal by unit train to Buyer's Generating Station(s) from the Cardinal Mine Delivery Point on the PAL Railway near Madisonville, Kentucky. Any savings in transportation expenses resulting from coal loaded at a Delivery Point closer to Buyer's Generating Station(s) than the Delivery Point of the Cardinal Mine, on the PAL Railway near Madisonville, Kentucky shall belong to Buyer. Seller shall be responsible for any pay the cost of repairs for any damages caused by Seller or its producer(s) to railcars owned or leased by Buyer while such railcars are in Seller's control or custody. Seller agrees to comply with the provision of PAL Tariff 4000 and its supplements or other tariffs as applicable. 3.5.1 BARGE DELIVERY. Buyer shall be entitled, upon prior reasonable notice to Seller, to change the specified mode of delivery for all or a portion of the Annual Quantity, subject to the availability of a barge loading facility. Any such change shall be made pursuant to Section 9 of this Agreement. In the event barge delivery is selected by Buyer for all or a portion of the Annual Quantity, the following provisions shall apply, effective on the date of election: The coal shall be delivered to Buyer F.O.B. barge, title and risk of loss of coal sold will pass to Buyer and the coal will be considered to be delivered when barges containing the coal are disengaged by Buyer's barging contractor from the loading dock. Buyer or its contractor shall furnish suitable barges in accordance with a delivery schedule provided by Buyer to Seller. Seller may deliver the coal to any loading facility ("Delivery Point"), provided, however, the total delivered cost of the coal by barge to Buyer's generating stations from any Delivery Point shall not exceed the total delivered cost of coal by barge to Buyer's Generating Station(s) form the Sebree Dock Point at mile point 44.0 on the Green River. Any savings in transportation expenses 5 resulting from coal loaded at a Delivery Point closer to Buyer's Generating Station(s) than the Delivery Point of the Sebree Dock shall belong to Buyer. Seller shall arrange and pay for all costs of transporting the coal from the mines to the loading docks and loading and trimming the coal into barges to the property draft and the proper distribution within the barges. Buyer shall reimburse Seller for such reasonable and actual trucking and transfer charges and shall arrange for transporting the coal by barge from the loading dock to its Generating Station(s) and shall pay for the cost of such transportation. For delays caused by Seller in handling the scheduling of shipments with Buyer's barging contractor Seller shall be responsible for any demurrage or other penalties assessed by said barging contractor (or assessed by Buyer relating to barges furnished by Buyer) which accrue at the Delivery point, including the demurrage, penalties for loading less than the specified minimum tonnage per barge, or other penalties assessed for barges not loaded in conformity with applicable requirements. Buyer shall be responsible to deliver barges in as clean and dry condition as practicable. Seller shall require of the loading dock operator that the barges and towboats provided by Buyer or Buyer's barging contractor be provided convenient and safe berth free of the wharfage, dockage and port charges; that while the barges are in the are and custody of the loading dock, all U.S. Coast Guard regulations and other applicable laws, ordinances, rulings, and regulations shall be complied with, including adequate mooring and display of warning lights; that any water in the cargo boxes of the barges be pumped out by the loading dock operator prior to loading; that the loading operations be performed in a workmanlike manner and in accordance with the reasonable loading requirements of Buyer and Buyer's barging contractor; and that the loading dock operator carry landing owners or wharfinger's insurance with basic coverage of not less than $300,000.00 and total of basic coverage and excess liability coverage of not less than $1,000,000.00, and 6 provide evidence thereof to Buyer in the form of a certificate of insurance from the insurance carrier or an acceptable certificate of self-insurance with requirement for notification of Buyer in the event of termination of the insurance. 4. QUALITY 4.1 QUALITY. This section effective March 1, 1989. The coal delivered hereunder shall conform to the following specifications on an "as received" basis: I. Standard Specification
Guaranteed Monthly Rejection Limits Specification Weighted Average (per shipment) - ----------------------------------------------------------------------- BTU/LB. min. 11,700 < 10,850> MOISTURE max. 7.7 lbs/MMBTU > 11.5 ASH max. 10.0 lbs/MMBU > 12.3 SULFUR max. 3.0 lbs/MMBTU > 3.3 SULFUR min. 1.8 lbs/MMBTU < 1.8> CHLORINE max. .05 lbs/MMBTU > .07 FLUORINE max. .013 lbs/MMBTU > .013 NITROGEN max. 1.15 lbs/MMBTU > 1.40 ASH/SULFUR RATIO min. 2 < 2> Size (3" x 0") Top size (inches) max. 3" > 3" Fines (% by wgt) passing 1/4 inch. screen max. 3" > 35% % BY WEIGHT: VOLATILE max. 38 > 38 VOLATILE min. 29 < 29> FIXED CARBON max. 50 > 50 FIXED CARBON min. 42 < 40> GRINDABILITY (HGI) min. 55 < 50> SLAGGING FACTOR* max. 1.6 > 1.9 FOULING FACTOR** max. 0.2 > 0.4 ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) - ---------------------------------------- 7 REDUCING ATMOSPHERE - -------------------- Initial Deformation min. 1940 min. 2000 Softening (H=W) min. 2035 min. 2100 Softening (H=1/2 W) min. 2085 min. 2200 Fluid min. 2190 min. 2300 OXIDIZING ATMOSPHERE - -------------------- Initial Deformation min. 2300 min. 2350 Softening (H=W) min. 2330 min. 2400 Softening (H=1/2 W) min. 2425 min. 2500 Fluid min. 2490 min. 2525 * Slagging Factor (R/s)=(B/A) x (Percent Sulfur by Weight/Dry) ** 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 0 DIVIDED BY Ca0 + Mg0 + Na 0 + K 0) -------------------------------------------- 2 3 2 2 (Si0 + A1 0 + T10 ) 2 2 3 2 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 thirty percent (30%) by weight of coal that will pass through a screen having circular perforations one-quarter (1/4) of an inch in diameter. [Note: As used herein > means greater than; < means less than]. 4.2 SHIPMENT. As used herein, a shipment shall mean one barge load, a barge lot load, or one unit trainload, as the case may be. 4.3 REJECTION. a. Buyer has the right, but not the obligation, to reject any shipment or car load(s) which fail(s) to conform to the Rejection Limits set forth in Section 4.1 or contains 8 extraneous materials or improperly sized coal. Buyer must reject such coal within seventy-two (72) hours of receipt of the coal analysis provided for in Section 5.3 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 if the coal is rightfully rejected. Seller shall replace the rejected coal within five (5) working days with coal conforming to the Rejection Limits set forth in Section 4.1. 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 an equivalent amount of coal from another source in order to replace the rejected coal and Seller shall reimburse Buyer for any amount that the total delivered cost to Buyer of such coal purchased from another source exceeds the then current delivered cost of coal sold to Buyer under this Agreement. Seller shall be responsible to pay or reimburse Buyer for any and all freight or transportation expenses that have been incurred for rightfully rejected coal. b. If Seller notifies Buyer prior to receipt of the shipment by Buyer at the Generating Station(s) that such shipment fails to conform to the Rejection Limits in Section 4.1, then Buyer has the option to accept or reject such shipment. If such shipment is not accepted by Buyer it shall not be considered as a rejection under paragraph a, or subject to the penalty set forth in paragraph c. If Buyer chooses to accept such non-conforming coal, such shipment will be considered as a delivery of a part of the quantity Buyer is obligated to purchase from Seller and shall not be considered as part of the Monthly Weighted Average specification set forth in Section 4.1, providing Buyer and Seller have agreed to a price for such non-conforming coal. In the event the results of the analysis of such shipment do conform to the Rejection Limits set forth in Section 4.1, Buyer shall pay the price as established under Section 6. 9 c. If Buyer unloads 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 4.1 or because such shipment contained extraneous materials or improperly sized coal and Seller had not advised prior to unloading that such shipment is a non-conforming shipment, then such non-conforming coal shall be deemed accepted by Buyer; however, the price shall be adjusted in accordance with Section 6 and the quantity Buyer is obligated to purchase from Seller, at Buyer's sole option, shall be reduced in each calendar year 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, etc., the estimated weight of such materials shall be deducted from the weight of that shipment. 4.4 SUSPENSION AND TERMINATION. a. If the coal sold hereunder fails to meet one or more of the Monthly Average Guarantees set forth in Section 4.1 for any 3 months in a 6 month period for moisture in a 6 month period for any other specification(s), or if 9 barge shipments in a 30 day period are rejected or rejectable by Buyer, or if Buyer receives at Generating Station(s) 2 unapproved rail shipments which are rejectable under Section 4.3, in any 30 day period, Buyer may upon notice confirmed in writing, suspend future shipments except shipments already loaded into barges and/or railcars. Seller shall, within 10 days, provide Buyer with reasonable assurances that subsequent monthly deliveries of coal shall meet or exceed the Monthly Average Guarantees set forth in Section 4.1. or that the source will exceed the rejection limits set forth in Section 4.1. If Seller fails to provide such assurances within said 10 day period, Buyer may terminate this Agreement on 5 days notice. A waiver of this right for any one period by Buyer shall not constitute a waiver for subsequent periods. If Seller provides such assurances to Buyer's 10 reasonable satisfaction, shipments hereunder shall resume and any tonnage deficiencies resulting from suspension may be made up at Buyer's sole option. Buyer shall not unreasonably withhold its acceptance of Seller's assurances, or delay the resumption of shipment. If Seller, after such assurances, fails to meet the Monthly Average Guarantees for moisture or BTU's due to whether for 3 months within the next 6 months or for 1 month within the next 6 months for any other Monthly Average Guarantee or if 3 barge shipments or 1 rail shipment are rejected or are rejectable within one month during such six month period, then Buyer may terminate this Agreement and purchase alternative coal and recover from Seller as damages the difference between the cost of cover and the contract price herein, or such other entitlement to damages as may be available to Buyer at law or in equity. 5. WEIGHTS, SAMPLING AND ANALYSIS 5.1 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. 5.2 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 11 laboratory at Buyer's expense in accordance with A.S.T.M. specifications. Samples for analyses shall be taken by any reliable and industry accepted standard, 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 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 3 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, and one part ("Referee Sample") shall be retained by Buyer for a period of 45 days. Seller shall be given timely and routine copies of all analyses made by Buyer. 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, 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 within 30 days of the date of sampling, 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. The analysis of the Independent Lab shall control to the extent provided in this Section. A dispute shall be deemed not to exist and 12 Buyer's analysis shall prevail if the analysis of a sample made by the commercial testing laboratory differs from the analysis of Buyer by an amount equal to or less than: (i) 0.50% moisture or (ii) 0.50 ash on a dry basis or (iii) 100 Btu/lb. on a dry basis, or (iv) 0.10% sulfur on a dry basis. The cost of the analysis made by the Independent Lab shall be borne by Seller if Buyer's analysis prevails and by Buyer if the analysis of the Independent Lab prevails. 5.3 FREEZE CONDITIONING. At Buyer's request, Seller shall treat (or have treated) any shipment of coal hereunder with a freeze conditioning agent (No. 8897, supplied by Nalco Chemical Co., or equivalent) in order to prevent deterioration in coal quality during shipment. If requested by Buyer, Seller shall also treat (or have treated) any rail cars specified by Buyer with a side release conditioning agent (No. 8885, supplied by Nalco Chemical Co., or equivalent). The prices for such chemical treatment effective on the date of execution of this Agreement shall be $.47 per ton of coal or $.15 per ton per application for railcar treatment, as the case may be. Once each year beginning on September 1, 1989, prices shall be subject to review at the request of either party for revisions to become effective on October 1. The parties shall negotiate in good faith to conclude agreement on price revisions, if any. In the vent of failure to agree within ninety (90) days after commencement of negotiations, the existing prices shall remain in effect until the next review period. If after renewing negotiations for an additional ninety (90) days during the ensuing review the parties are still unable to agree, then either shall have the right to discontinue performance of freeze conditioning services. Nothing herein shall require Buyer to contract with Seller for such services. Invoicing procedures shall be pursuant to Section 7.3. 13 6. PRICE 6.1 PRICE. The Base Price of Coal is $.83120/MMBTU, F.O.B. rail car, effective March 1, 1989, and continuing until December 31, 1989. Thereafter, the Base Price shall be in accordance with the following schedule:
Year Base Price, FOB Rail* Effective Date ---- --------------------- -------------- 1990 $ .85470 January 1, 1990 1991 $ .89085 January 1, 1991 1992 $ .92410 January 1, 1992 1993 $ .96171 January 1, 1993 1994 $1.00094 January 1, 1994 1995 $1.04017 January 1, 1995 * in $/MMBTU
The Base Price is inclusive of all federal, state, municipal and local taxes, fees and costs of any kind whether arising from government law, rule, regulation or otherwise, including, without limitation, all costs of conforming to federal and state mining and reclamation laws, rules and regulations as of January 1, 1991. In the event any new laws, rules, regulations or ordinances are imposed subsequent to January 1, 1991, Buyer or Seller, as appropriate, shall compute and document the effect of such laws, rules, regulations or ordinances on Base Price and, if the effect is material (as hereafter defined), either party may propose an increase or decrease as the case may be in Base Price. "Material" as used herein shall mean increases or decreases in taxes, fees or costs totaling more than three percent (3%) of the then current Base Price, which are attributable to any such new laws, rules, regulations or ordinances. Any such proposal shall be made in writing and shall include such information and data as is reasonably necessary to substantiate the proposal. The parties shall thereupon endeavor in good faith to reach an agreement with respect to any revision in Base Price. If no agreement is concluded within sixty (60) days after the date of 14 receipt of any such proposal, the matter shall be submitted for resolution under Section 14 "Disputes" of this Agreement. The following additional conditions shall apply to any such proposal: a. RECORDS AND AUDIT. Seller shall maintain all records relating directly or indirectly to any proposed revision in Base Price and shall furnish to Buyer substantiation thereof, in form and detail satisfactory to Buyer. Buyer shall have the right at all reasonable times to audit and inspect such records. b. PRICE REVIEW. Buyer shall have the right of Price Review at any time under Section 6.2 below. 6.2 PRICE REVIEW. The Base Price and Quality Price Adjustment provisions in Section 6 of this Agreement shall be subject to review at the request of either party, for revision(s) to become effective on January 1 of 1991 and on every fifth anniversary date thereafter if this Agreement is renewed (e.g., January 1, 1996; January 1, 2001 etc.). Buyer shall also have the right of review under this Section at any time during any Agreement Year as a result of any proposal made by Seller under Section 6.1. The party requesting such a review shall give written notice of its request to the other party on or before December 1st of the year prior to the effective dates. The notice shall describe the proposed adjustment(s) and the reasons therefor. For a period of ninety (90) days following receipt of such notice, Buyer and Seller shall diligently and in good faith endeavor to reach agreement as to reasonable revision(s) in Base Price or adjustment provisions. If the parties do not agree within such ninety (90) day period (or any mutually agreed extension thereof), either party may terminate this Agreement by giving at least nine (9) months written notice to the other and the then current Base Price shall remain in effect 15 until the Agreement is terminated. If neither party gives the aforesaid nine (9) months notice, the then current Base Price shall remain in effect until the next price review date or the termination of this Agreement, as the case may be. 6.3 QUALITY PRICE ADJUSTMENTS. This section effective April 1, 1989. The Base Price is based on coal having the guaranteed "as received" monthly weighted average specifications as set forth in Section 4.1. Quality Price Adjustments (bonuses and/or penalties) shall be made to reflect variances from the Guaranteed Monthly Weighted Averages set forth in Section 4.1 as determined pursuant to Section 5.2. There shall be no sulfur bonus for coal which has a sulfur content less than 1.80 lbs/MMBTU.
The penalty and bonus values used are: PENALTY BONUS $/MMBTU $/MMBTU ------- ------- BTU/LB. 0.2604 0.1354 SULFUR 0.1232 0.1084 ASH 0.0083 0.0073 MOISTURE 0.0016 0.0014
These Bonus and Penalty amounts above are stated in 1988 dollars. These Bonus and Penalty amounts shall be adjusted annually by the change in the Producer's Price Index (PPI), and adjusted, for all Commodities, Table 3. Effective January 1, 1990, each amount shall be revised based on the percentage change in the PPI from November 1, 1988 through November 1, 1989 as follows: PPI on 11/1/89 x each Bonus and Penalty Amount = Revised Bonus and Penalty - -------------- Amount PPI on 11/1/88 (round to 4 decimal places) 16 Thereafter, on each January 1, beginning 1991, and continuing throughout the term of this Agreement, the Bonus and Penalty amounts shall be revised based upon the percentage change in the PPI for the 12 month period ended on November 1 of the immediately preceding year. 6.4 PAYMENT CALCULATION. Exhibit B attached hereto shows the methodology for calculating the coal payment and adjustments to Seller for the month Seller's coal was unloaded by Buyer. If such Adjustments result in a payment to Buyer, Buyer shall apply credit to amounts owed Seller for the calendar month the coal was unloaded. If such Adjustments result in a payment to the Seller, Buyer shall pay Seller at the same time Buyer makes payment to Seller for the coal unloaded during that calendar month. 7. INVOICES, BILLING AND PAYMENT 7.1 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice Buyer at the current Base Price for all coal unloaded in a calendar month by the fifteenth of the following month. 7.2 PAYMENT PROCEDURES FOR COAL SHIPMENTS. Payment for coal unloaded in a calendar month shall be mailed by the 20th of the month following the month of unloading. Buyer shall mail all payments to Seller's account at Citizens Fidelity Bank, Louisville, Kentucky. 7.3 INVOICE AND PAYMENT PROCEDURES FOR FREEZE CONDITIONING. Seller shall invoice Buyer for freeze conditioning treatments for coal shipments or rail cars by the 15 of the month following the month in which treatment was provided. Buyer will make payment by the 20th of such month. Invoices shall be at the rates established under Section 5.3 and only for treatments actually made. 7.4 WITHHOLDING. Buyer shall have the right to withhold from payment of any billing or billings the amount of any sums which it is not able in good faith to verify or which it otherwise in good faith disputes, such right to withhold to continue for the duration of the dispute or inability 17 to verify. Buyer shall notify Seller promptly in writing of any such issue, stating the basis of its claim and the amount it intends to withhold, and the parties agree to review the matter in detail within ten (10) days after Seller's receipt of such notice. In the event the parties are not able promptly to agree to a resolution, the matter shall be resolved under the Disputes provision of this Agreement. In the event and to the extent that any dispute or verification issue is resolved in Seller's favor, Seller shall add the unpaid amount to the next invoice, plus interest at the prime rate of borrowed funds charged by Manufacturers Hanover Bank as published in the most recently available Wall Street Journal, for the period between the date on which the amount would normally be paid and the actual invoice date, and Buyer shall pay such extra amount in accordance with the procedures hereof. In the event and to the extent that any dispute or verification issue is resolved in Buyer's favor, Seller shall promptly issue a credit memorandum covering the amount in question. 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. 8. FORCE MAJEURE 8.1 EVENTS OF FORCE MAJEURE. Performance of the obligations of either party hereto shall be excused to the extent prevented by an event of force majeure. As used herein, an event of force majeure shall mean an act of God; strike, lockout or other labor dispute; sabotage; fire; flood; war; riot or insurrection; explosion; accident; embargo; blockade; inability to secure supplies, fuel, power, governmental authorization or permit; breakdown of or damage to machinery, plants or equipment; interruption or shortage of transportation arrangements or equipment; regulation, rule, law, order, act or restraint of any civil or military authority; or any 18 other event, whether of the kind herein enumerated or otherwise, which is beyond the control and without the fault or negligence of the party affected thereby and which wholly or partially prevents, interrupt or delays performance hereunder. An event is beyond the control of a party if it cannot be prevented or eliminated by the exercise of due diligence or its prevention or elimination would be accomplished only at an excessive or unreasonable cost. The party claiming excuse hereunder shall give the other party prompt notice of such event. Tonnage deficiencies resulting from an event of force majeure shall be made up by mutual agreement on a reasonable schedule. As used herein, the term "Seller" shall include any party mining, preparing, hauling, loading or transporting coal to Seller for resale to Buyer under this Agreement. 8.2 ENVIRONMENTAL FORCE MAJEURE. The parties recognize that, during the continuance of this Agreement, legislative or regulatory bodies or the courts may adopt laws, regulations, policies and/or restrictions relating to air pollution or otherwise which will make it impossible or commercially impracticable for Buyer to utilize this or like kind and quality coal which thereafter would be delivered hereunder. If as a result of the adoption of such laws, regulations, policies, or restrictions, or change in the interpretation or enforcement thereof, Buyer decides that it will be impossible or commercially impracticable (uneconomical) for Buyer to utilize such coal, Buyer shall so notify Seller, and thereupon Buyer and Seller shall promptly consider whether corrective actions can be taken in the mining and preparation of the coal at Seller's mine and/or in the handling and utilization of the coal at Buyer's generating station; and if in Buyer's judgment such actions will not, without unreasonable expense to Buyer, make it possible and commercially practicable for Buyer to so utilize coal which thereafter would be delivered hereunder without violating any applicable law, regulation, policy or order, Buyer shall have the right, upon the later 19 of 60 days notice to Seller or the effective date of such restriction, to terminate this Agreement without further obligation hereunder on the part of either party. Buyer's decisions and opinions with respect to this Section 8.2 shall be final and not subject to question or dispute by Seller. 9. CHANGES. Buyer may, at any time with Seller's mutual agreement by written notice pursuant to Section 10 of this Agreement, make changes within the general scope of this Agreement in any of the following: quality of coal or coal specifications, quantity of coal, method or time of shipments, place of delivery (including transfer or title and risk of loss), method(s) of weighing, sampling or analysis and such other provisions as may affect the suitability and amount of coal for Buyer's generating stations. If any such change causes an increase or decrease in the then current Base Price per ton of coal, or in any other provision of this Agreement, an equitable adjustment shall be made in: Base Price, whether current or future or both, and/or in such other provisions of this Agreement as are affected directly or indirectly by such change, and the Agreement shall thereupon be modified in writing accordingly. Any claim by the Seller for adjustment under this Section shall be asserted within thirty (30) days after the date of Seller's receipt of the written notice of change, it being understood, however, that Seller shall not be obligated to proceed under this Agreement as changed until an equitable adjustment has been mutually agreed upon. The parties agree to negotiate promptly and in good faith to agree upon the nature and extent of any equitable adjustment. Failure to agree within one hundred twenty (120) days after the date of assertion of any claim shall be a dispute within the meaning of Section 14 "Disputes" of this Agreement, and the parties shall refer the matter promptly for resolution under said Section 14. 20 10. NOTICES 10.1 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 if delivered in person, transmitted by telegraph, telex, or telecopier, 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: If to Seller: Shawnee Coal Company Roberts Bros. Coal Co., Inc. 4205 Hillboro Road Lafoon Trail Nashville, TN 37215 1223 Madisonville, KY 42431 If to Buyer: Senior Vice President - Operations Louisville Gas and Electric Company 311 West Chestnut Street P.O. Box 32010 Louisville, KY 40232 10.2 CHANGE OF PERSON OR ADDRESS. Either party may change the person or address specified above upon giving notice to the other party of such change. 10.3 ELECTRONIC DATA TRANSMITTAL. Seller hereby agrees, at Seller's cost, to electronically transmit shipping notices and/or other data to Buyer in a format acceptable to and established by Buyer. Buyer shall provide Seller with the appropriate format and will inform Seller as to the electronic data requirements at the appropriate time. 11. EARLY TERMINATION. The parties recognize that, conditions not now foreseen could arise in which either Buyer or Seller, whether for economic or other compelling reasons, would 21 desire to terminate this Agreement, in whole or in part, in advance of the expiration date. Accordingly, it is agreed that for whatever reason, each party shall have the right of early termination, in whole or in part, of its rights and obligations under this Agreement, subject to the provisions of this Agreement. The party desiring to exercise its rights of early termination shall give written notice thereof to the other party and pay the price for early termination as described herein. Notice may be given by either party no later than three (3) months before the end of any Agreement year, and this Agreement will be terminated at the end of such year. The price paid for such early termination shall be 10% of Base Price (not to exceed $2.00/Ton) on the effective date of termination times the minimum tonnage remaining from the effective date of the termination until the next price review period, as set forth in Section 6.2. 12. RIGHT TO RESELL. Buyer shall have the unqualified right to sell all or any of the coal purchased under this Agreement. In the event Buyer resells any or all of the coal purchased hereunder that is not unloaded by Buyer, Seller's weights and analyses shall be used to determine the weights, sampling and analysis (determined in accordance with ASTM standards) of such coal resold. 13. INDEMNITY 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) 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, 22 or for any failure of Seller to comply with laws, regulations or ordinances, or which arise out of the acts or omissions of Seller in the performance of this Agreement. 13.2 INSURANCE. Seller agrees to carry insurance coverage with minimum limits as follows: (1) Commercial General 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 $3,000,000 for any one occurrence. (4) Kentucky Workers Compensation and Employer's Liability with statutory limits. (5) 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 Seller's original contract. 14. DISPUTES. Except as otherwise specifically provided in or permitted by this Agreement, all disputes, differences of opinion, or controversies arising in connection with this Agreement shall be resolved first, by the use in good faith of mutual best efforts to arrive at an agreeable resolution. If, after negotiating in good faith for a period of ninety (90) days, the parties are unable to agree, then either shall have the right to terminate this Agreement by giving ninety (90) days written notice to the other. 15. TERMINATION FOR DEFAULT. In the event of the failure of either party to comply with any material obligation of this Agreement, either party shall have the right to terminate this Agreement at any time by giving to the other 120 days' notice in writing of its intention to do so, specifying the default complained of. At the expiration of said 120 days, unless the party in 23 default shall have made good such default, the party not in default shall have the right at its election to terminate this Agreement forthwith. This right shall be in addition to the rights provided to either party in other portions of this Agreement and by law, or in equity. 16. CONSTRUCTION OF AGREEMENT 16.1 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. 16.2 HEADINGS. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning or interpretation of the Agreement. 16.3 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. 16.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement shall be cumulative and in addition to other remedies provided by law. 16.5 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. 16.6 BINDING EFFECT. This Agreement shall bind and inure to the benefit of the parties and their successors and assigns. 24 16.7 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. 16.8 ENTIRE AGREEMENT.. This instrument contains the entire Agreement between the parties as to coal produced and sold from the Coal Property, and there are no representations, understandings or agreements, oral or written, which are not included herein. 16.9 AMENDMENTS. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by parties hereto. 17. AGENCY RELATIONSHIP; SELLER'S LIABILITY 17.1 AGENCY. The relationship between Roberts Bros Coal Co. Inc. and Shawnee Coal Company, Inc. is that of principal and agent. Any action by Shawnee Coal Company, Inc. under this Agreement shall be binding on Roberts Bros. Coal Co. Inc. and vice versa and both Shawnee Coal Company, Inc. and Roberts Bros. Coal Co. Inc. hereby indemnify and hold Buyer harmless from and against any and all claims, losses, actions, damages or costs of whatever nature arising out of or resulting from the agency relationship. 17.2 JOINT AND SEVERAL LIABILITY. The obligations and liabilities of Seller under this Agreement shall be the joint and several obligations and liabilities of Roberts Bros. Coal Co. Inc. and Shawnee Coal Company, Inc. 25 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed as of the date first above written. BUYER: ______________________________ By: _______________________________ Attest Title: ____________________________ SELLER: ______________________________ By: _______________________________ Attest Title: ____________________________ SELLER: ______________________________ By: _______________________________ Attest Title: ____________________________ 26 LEGEND 1. #4 Coal Mason Property 91.8274 AC Ht. Coal 48" 661,157.28 Tons 2. #8 Coal Mason Property 1,604.2241 AC Ht. Coal 24" 4,775,206.76 Tons 3. #4 Coal White Plains 56.9330 AC Ht. Coal 30" 256,198.50 Tons 4. #9 Coal Highway 70 Miracle 11.1843 AC Coal Ht. 60" 100,658.70 Tons 5. #11 Coal Warrior 3,133.1497 AC Coal Ht. 66" 31,018,182.03 Tons 6. #9 Coal Warrior 5,178.1451 AC Coal Ht. 60" 46,603.305.90 Tons 7. #4 Coal Donaldson Creek 509.6419 AC Coal Ht. 48" 3,669,421.88 Tons 8. #14 Coal T&N Powell 96.6639 AC Coal Ht. 108" 1,565,955.18 Tons 9. #6 Coal Diamond 1,629.00 AC Coal Ht. 40" 9,774,000.00 Tons 10. Christian Strip 2,445,200.70 Tons #13 Coal #12 Coal (From Donan Reserve Study) 4,087,571.10 Tons #11 Coal 7,155,174.60 Tons 11. #9 Coal Christian 112.0321 AC Coal Ht. 60" 1,008,288.90 Tons 12. Charleston Washer Truck and Rail Loading Facility 14. #9 Miracle 77.78 AC Coal Ht. 60" 700,000.00 Tons MINES IN PRODUCTION STRIP RESERVES UNDERGROUND RESERVES TOTAL EVALUATED COAL COSTS FOR P.O. OR CONTRACT NO.: SECTION I. Base Data
1) Enter Base F.O.B. price per ton ($/ton) [1] $_______/ton 1a) Enter tons of coal delivered [1a] $_______/tons 2) Enter guaranteed average heat content (BTU/lb) [2] $_______ BTU/LB 2r) Enter as received monthly average heat content (BTU/lb) [2r] $_______ BTU/LB 2a) Enter Energy delivered (in MMBTU), [ (Line 1a) * 2,000 lb/ton * (Line 2r)]* MMBTU/1,000,000 BTU [ ( ) * 2,000 * ( ) ]/1,000,000 + [2a] $_______ MMBTU 2b) Enter Base F.O.B. price per MMBTU, { [(Line 1) / (Line 2)] * (1 ton/2,000 lb) } * (1,000,000 BTU/MMBTU) { [ ( ) / ( ) ] / 2,000 } * 1,000,000 = [2b] $_______ MMBTU 3) Enter guaranteed monthly average maximum sulfur [3] $_______ LBS/MMBTU 3r) Enter as received monthly average sulfur [3r] $_______ LBS/MMBTU 4) Enter guaranteed monthly average maximum ash [4] $_______ LBS/MMBTU 4r) Enter as received monthly average ash [4r] $_______ LBS/MMBTU 5) Enter guaranteed monthly average maximum moisture [5] $_______ LBS/MMBTU 5r) Enter as received monthly average moisture [5r] $_______ LBS/MMBTU
SECTION II. Penalties and Bonuses Use the appropriate lines under either the Penalty or Bonus section according to the value of 2r, 3r, 4r and 5r.
- - $/MMBTU PENALTIES Assign a (-) to all penalties (round to 5 decimal places). 6p) BTU/LB: If Line 2r is less than Line 2, { 1 - [ ( Line 2r ) / ( Line 2 ) ] } * $0.2604 / MMBTU { 1 - [ ( ) / ( ) ] } * $0.2604 = [6p] $_______ /MMBTU 7p) Sulfur: If Line 3r is greater than Line 3, [(Line 3r)-(Line 3)] * $0.1232/lb [7p] sulfur [ ( ) - ( ) ] * 0.1232 = $_______ /MMBTU 8p) Ash: If Line 4r is greater than Line 4, [ (Line 4r) - (Line 4 ] * $0.0083/lb ash [ ( ) - ( ) ] * $0.0083 = [8p] $_______ /MMBTU 9p) Moisture: I*f Line 5r is greater than Line 5, [ (Line 5r) - (Line 5) ] * $0.0016/lb moisture [ ( ) - ( ) ] * $0.0016 = [9p] $_______ /MMBTU BONUSES Assign a (+) to all Bonuses (round to 5 decimal places). 6b) BTU/LB: If Line 2r is greater than Line 2, { [ (Line 2r) / (Line 2) ] - 1 } * \ $0.1354/MMBTU { [ ( ) / ( ) ] - 1} * $0.1354 = [6b] $_______ /MMBTU 7b) Sulfur: If Line 3r is between Line 3 and 1.8 lb/MMBTU, [ (Line 3) - (Line 3r) ] * $0.1084/lb sulfur (NO BONUS IF LINE 3R IS LESS THAN 1.8) [ ( ) - ( ) ] * $0.1084 = [7b] $_______ /MMBTU 8b) Ash: If Line 4r is less than Line 4, [ (Line 4) - (Line 4r) ] * $0.0073/lb ash [ ( ) - ( ) ] * $0.0073 = [8b] $_______ /MMBTU 9b) Moisture: If Line 5r is less than Line 5, [ (Line 5) - (Line 5r) * $0.0014/lb ] moisture [ ( ) - ( ) ] * $0.0014 = [9b] $_______ /MMBTU Determine total Penalty/Bonus adjustment as follows: Assign a (-) to all Penalties and a (+) to all Bonuses and enter the number for: Line 6p or 6b $_______ /MMBTU Line 7p or 7b $_______ /MMBTU Line 8p or 8b $_______ /MMBTU Line 9p or 9b $_______ /MMBTU 10) Total Penalties and/or Bonuses (+/-) ( ) + ( ) + ( ) + ( ) = $_______ /MMBTU (algebraic summation of the above) 11) Total evaluated coal price = (Line 2b) + (Line 10) ( ) + ( ) = $_______ /MMBTU 12) Total premium/penalties price adjustment for Energy delivered: (Line 2a) * (Line 10) (+/-) ( ) * ( ) = $_______ 13) Total base cost of coal (Line 2a) * (Line 2b) ( ) * ( ) = $_______ 14) Total coal payment for month (Line 12) + (Line 13) ( ) + ( ) = $_______ (algebraic sum)
EX-10.42 3 EXHIBIT 10.42 COAL SUPPLY AGREEMENT Amendment No. 1 EXHIBIT 10.42 COAL SUPPLY AGREEMENT THIS AMENDMENT IS entered into, effective as of January 1, 1991, by and between Louisville Gas and Electric Company (hereinafter referred to as Buyer), whose address is: 820 W. Broadway, Louisville, Kentucky 40232 and Shawnee Coal Company (herein referred to as "Seller"), whose address is: 4205 Hillsboro Road, Nashville, Tennessee 73215, and Roberts Bros. Coal Company (herein referred to as "Seller"), whose address is: Lafoon Trail, P.O. Box 1223, Madisonville, Kentucky 42431. In consideration of the agreements herein contained, the parties hereto agree as follows: 1. AMENDMENTS The Coal Supply Agreement heretofore entered into by the parties, dated effective August 9, 1989, (hereinafter referred to as "Coal Supply Agreement"), is hereby amended as follows: 1.1 Article 2.2 set forth to this Coal Supply Agreement is amended to add the following: "As of August 31, 1990, a balance of 209,473.50 tons (189,000.00 prescheduled and 20,473.50 deficiency) remained to be delivered during the 1990 contract year at the 1990 contract base price ($0.85470/MMBTU). Seller shall use its best efforts and full abilities to insure the delivery of the prescheduled and deficient tonnage prior to December 31, 1990. However, in the event the 20,473.50 tons of deficient coal is scheduled by Buyer, and for reasons other than those which are excusable under Section 8. FORCE MAJEURE, Seller is unable to meet the delivery requirements of the contract as amended hereunder by December 31, 1990, Seller shall delivery the remaining deficient tonnage during the 1991 Contract year at the 1990 contract price. The first tonnage delivered by Seller during the 1991 contract year shall be deemed to be the deficient tonnage and shall be in addition to the contract tonnage requirements for the 1991 contract year." 1.2 Article 2.3 set forth to this Coal Supply Agreement is amended to add the following: "Buyer shall have the option of the first right of refusal to purchase up to an additional 500,000 tons, if available, per year for 1991 through 1995 and for any additional renewal extensions thereafter if exercised by Buyer. Seller shall notify Buyer in writing whenever additional coal is available. Buyer must notify Seller, within 30 (thirty) calendar days from date Seller offers the additional tonnage, of its interest in exercising this option. After Buyer's notification of interest, Buyer and Seller shall negotiate in good faith for 30 days to reach a mutual agreement for the supply of such tonnage. If Buyer rejects Seller's offer, or the parties are otherwise unable to reach agreement on price, quality, or other terms and conditions within the periods indicated above (60 calendar days from the date of Seller's of first notice), Seller shall have the right to place the coal on the market for purchase by other buyers at the price, quality and other terms and conditions Seller may deemed favorable." 1.3 The Coal Supply Agreement is amended to add the following: "Section 18 CONFIDENTIAL INFORMATION. Specifications, annual quantities, pricing and other information obtained by Seller from Buyer in connection with this Coal Supply Agreement shall be held in confidence by Seller and shall not be used by Seller for any purpose other than for the supply of coal or as authorized in writing by Buyer." 2. PRICING SUMMARY 2.1 The Base Price set forth in the Coal Supply Agreement is hereby changed as follows to Seller for full and complete performance by Seller of this Amendment in full compliance with all terms and conditions of the Coal Supply Agreement:
2.1.1 Original Base Net Adjustment New Total Price F.O.B. Pursuant to This Base Price Effective Year Rail Amendment F.O.B. Rail Date ---- ------------- ---------------- ----------- --------- 1990 $0.85470 $___________ $0.85470 January 1, 1990 COAL SUPPLY AGREEMENT Amendment No. 1 1991 $0.89085 $0.01282 $0.90367 January 1, 1991 1992 $0.92410 $0.01282 $0.93692 January 1, 1992 1993 $0.96171 $0.01282 $0.97453 January 1, 1993 1994 $1.00094 $0.01282 $1.01376 January 1, 1994 1995 $1.04017 $0.01282 $1.05299 January 1, 1995 *All Prices in $/MMBTU
3. STATUS OF COAL SUPPLY AGREEMENT As amended herein, the Coal Supply Agreement shall continue in full force and effect. IN WITNESS WHEREOF, the parties hereto have executed this Amendment on the day and year below written, but effective as of the day and year first set forth above. Shawnee Coal Company Louisville Gas and Electric Company By: ___________________________ By:_________________________________ Title: __________________________ Title:______________________________ Date: ___________ Date: _____________ Roberts Bros. Coal Co., Inc. By: ___________________________ Title: __________________________ Date: ___________ 2 EX-10.43 4 EXHIBIT 10.43 Shawnee Coal Company Coal Supply Agreement Amendment No. 2 EXHIBIT 10.43 AMENDMENT TO CONTRACT THIS AMENDMENT IS entered into, effective as of November 27, 1991, by and between Louisville Gas and Electric Company (hereinafter referred to as "Buyer"), whose address is: 220 W. Main St., Louisville, Kentucky 40232 and Shawnee Coal Company (herein referred to as "Seller"), whose address is: 4205 Hillsboro Road, Nashville, Tennessee 37215 and Roberts Bros. Coal Company (also hereinafter referred to as "Seller") whose address is: LaFoon Trail, P.O. Box 1223, Madisonville, Kentucky 42431. In consideration of the agreements herein contained, the parties hereto agree as follows: 1. AMENDMENTS The Coal Supply Agreement heretofore entered into by the parties, dated effective August 9, 1989 and identified by the Contract Number set forth above, as previously amended by Amendment Number 1 thereto, (hereinafter referred to as "Agreement"), is hereby further amended as follows: 1.1 Article 2.1 ANNUAL QUANTITY set forth in this Agreement is amended as follows: "2.1 ANNUAL QUANTITY. This section effective January 1, 1989. Except as adjusted under Section 2.3, Seller shall sell and deliver and buyer shall purchase and accept delivery of the following annual tonnages ("Annual Quantity").
Additional Coal This Year This Amendment Quantity (Tons) ---- -------------- --------------- 1989 ________ 364,000 1990 ________ 364,000 1991 98,000 700,000 1992 400,000 + (20% exiting 1,300,000 base 750,000) 1993 ________ 1,125,000 1994 ________ 1,125,000 1995 ________ 1,125,000
1.2 Article 2.3 NOTIFICATION set forth in this Agreement is amended to read as follows: "2.3 NOTIFICATION. By December 1 of each Agreement year, Buyer shall specify by written notice to Seller the monthly quantities to be delivered in the following Agreement year. For 1993 and following years, upon 6 months notice to Seller, Buyer may change the quantity to be delivered under this Section within a range of +20% of specified - annual tonnage, except that in no event shall Buyer specify less than 900,000 tons. 2. PRICING SUMMARY 2.1 The Base Price set forth in the Coal Supply Agreement is hereby changed as follows as full compensation to Seller for full and complete performance by Seller of this Amendment in full compliance with all terms and conditions of the Coal Supply Agreement: Shawnee Coal Company Coal Supply Agreement Amendment No. 2
Original Base Net Adjustment Net Adjustment New Total Price F.O.B. Pursuant to Prior Pursuant to Pursuant to Year Rail Amendment This Amendment This Amendment ---- -------------- ---------------- -------------- -------------- 1990 $0.85470 $________ $________ $0.85470 1991 $0.89085 $0.01282 $________ $0.90367 1992 $0.92410 $0.01282 ($0.00427) $0.93265 1993 $0.96171 $0.01282 ($0.00427) $0.97026 1994 $1.00094 $0.01282 ($0.00427) $1.00949 1995 $1.04017 $0.01282 ($0.00427) $1.04872 * All Prices in $/MMBTU
3. STATUS OF AGREEMENT As amended herein, the Agreement shall continue in full force and effect. IN WITNESS WHEREOF, the parties hereto have executed this Amendment on the day and year below written, but effective as of the day and year first set forth above. Shawnee Coal Company Louisville Gas and Electric Company By: ___________________________ By: _________________________________ Title: __________________________ Title: ________________________________ Date: ___________ Date: _____________ Roberts Bros. Coal Co., Inc. By: ___________________________ Title: __________________________ Date: ___________ 2 EX-10.44 5 EXHIBIT 10.44 Shawnee Coal Company Coal Supply Agreement Amendment No. 3 EXHIBIT 10.44 AMENDMENT THIS AMENDMENT IS entered into, effective as of January 1, 1994, by and between Louisville Gas & Electric Company (hereinafter referred to as "Buyer"), whose address is: 220 W. Main Street, Louisville, Kentucky 40232 and Shawnee Coal Company (herein referred to as "Seller"), whose address is: 4205 Hillsboro Road, Nashville, Tennessee 37215 and Roberts Bros. Coal Company (also hereinafter referred to as "Seller"). Whose address is: LaFoon Trail, P.O. Box 1223, Madisonville, Kentucky 42431. In consideration of the agreements herein contained, the parties hereto agree as follows: 1. AMENDMENTS The Coal Supply Agreement heretofore entered into by the parties, dated effective August 9, 1989 and identified as Coal Supply Agreement set forth above, as previously amended by Amendment Numbers 1 and 2 thereto, (hereinafter referred to as "Agreement"), is hereby further amended as follows: 1.1 Article 1.1 TERM set forth in this agreement to the Contract is amended in its entirety as follows: "1.1 TERM. Except for specific effective dates described in specific sections herein, the term of this Agreement shall commence on March 1, 1989 and shall continue until and including December 31, 1996. Buyer shall have right, but not the obligation, to renew this Agreement for up to three (3) additional five (5) year periods, such right to be exercised by notice in writing to Seller no later than sixty (60) days prior to the end of the existing period. The Base Price upon any such renewal shall be agreed upon by the parties subject to the provisions of 6.2." 1.2 Article 2.1 ANNUAL QUANTITY set forth in this Agreement is amended as follows: "2.1 ANNUAL QUANTITY. This section effective January 1, 1989. Except as adjusted under Section 2.3, Seller shall sell and deliver and Buyer shall purchase and accept delivery of the following annual tonnages ("Annual Quantity").
Additional Coal This Year This Amendment Quantity (Tons) ---- -------------------- --------------- 1989 ________ 364,000 1990 ________ 364,000 1991 ________ 700,000 1992 ________ 1,300,000 1993 ________ 1,125,000 1994 90,000 1,215,000 1995 90,000 1,215,000 1996 1,215,000 1,215,000
1.3 Article 2.3 NOTIFICATION set forth in this Agreement is amended to read as follows: "2.3 NOTIFICATION. By December 1 of each Agreement year, Buyer shall specify by written notice to Seller the monthly quantities to be delivered in the following Agreement year. Buyer shall provide Seller with at least 30 days notice prior to the beginning of each quarter concerning the quantity of optional tonnage coal that the buyer elects to purchase during the upcoming quarter. For 1994 and following years, Seller will supply up to 300,000 additional tons of coal per year if requested by Buyer. Not more than 150,000 tons of additional coal is to be supplied in any two consecutive quarters and Seller is not required to supply more than 150,000 tons (optional plus base) of additional coal in any given month. SHAWNEE COAL COMPANY COAL SUPPLY AGREEMENT AMENDMENT NO. 3 1.4 Article 6.2 PRICE REVIEW set forth in this Agreement is amended in its entirety as follows: "6.2 PRICE REVIEW. If Buyer exercises its right to renew this Agreement by giving notice under Article 1.1 hereof, then the Base Price and Quality Price adjustment provisions in Section 6 of this Agreement shall be subject to review at the request of either party, for revision(s) to become effective for the renewal term. Buyer shall also have the right of review under this Section at any time during any Agreement Year as a result of any proposal made by Seller under 6.1. The party requesting such a review shall give written notice of its request to the other party within 30 days from the date of Buyer's notice to renew this Agreement. The notice shall describe the proposed adjustment(s) and the reasons therefor. For a period of ninety (90) days following receipt of such notice, Buyer and Seller shall diligently and in good faith endeavor to reach agreement as to reasonable revision(s) in Base Price or adjustment provisions. If the parties do not agree within such ninety (90) day period (or any mutually agreed extension thereof), either party may terminate this Agreement by giving at least nine (90) months written notice to the other and the then current Base Price, quantity, and all other terms and conditions hereof shall remain in effect until the Agreement is terminated. If neither party gives the aforesaid nine (90) months notice, the then current Base Price, quantity, and all other terms and conditions hereof shall remain in effect until the next price review date or the termination of this Agreement, as the case may be." 1.5 Article 6.3 QUALITY PRICE ADJUSTMENTS set forth in this Agree is amended to add the following at the end: "6.3 QUALITY PRICE ADJUSTMENTS. Notwithstanding the above, the Bonus and Penalty amounts shall escalate one additional time scheduled to take effect 1/1/94, then will remain fixed for the duration of Contract." 1.6 Article 18 SHAWNEE TERMINATION is added at the end of the Agreement as follows: "18 SHAWNEE TERMINATION Notwithstanding any other provision in this Agreement, with respect to Shawnee Coal Company, Inc. only, this Agreement will terminate on December 31, 1995. Such termination will not relieve Shawnee Coal Company, Inc. of any of its liabilities or obligations to Buyer which accrue hereunder by December 31, 1995. This Agreement will continue in full force and effect between Roberts Bros. Coal Company, Inc. and Buyer through the entire term of this Agreement and any renewal terms as set forth herein". 2. PRICE SUMMARY 2.1 The Base Price set forth in the Coal Supply Agreement is hereby changed as follows as full compensation to Seller for full and complete performance by Seller of this Amendment in full compliance with all terms and conditions of the Coal Supply Agreement:
Original Base Net Adjustment Net Adjustment Net Adjustment Few Total Price for Price F.O.B. Pursuant to Pursuant to Pursuant to Base Price Optional Year Rail Amendment 1 Amendment 2 Amendment 3 F.O.B. Rail Tonnage ---- ------------- -------------- -------------- -------------- ----------- --------- 1990 $0.85470 $________ $________ $________ $________ $________ 1991 $0.89085 $________ $________ $________ $________ $________ 1992 $0.92410 $________ $________ $________ $________ $________ 1993 $0.96171 $________ $________ $________ $________ $________ 1994 $1.00094 $0.01282 ($0.00427) ($0.00427) $1.00522 $0.96676 1995 $1.04017 $0.01282 ($0.00427) ($0.00427) $1.04445 $1.00599
2 Shawnee Coal Company Coal Supply Agreement Amendment No. 3 1996 $________ $________ $________ $________ $1.08518 $1.04672 *All Prices in $/MMBTU
Any additional tonnage as described in Article 2.3 NOTIFICATION -- shall be .90 cents per ton ($0.03846/MMBTU) less than established price for that year. 3. STATUS OF AGREEMENT As amended herein, the Agreement shall continue in full force and effect. IN WITNESS WHEREOF, the parties hereto have executed this Amendment on the day and year below written, but effective as of the day and year first set forth above. Shawnee Coal Company Louisville Gas and Electric Company By: ___________________________ By:_________________________________ Title: __________________________ Title:______________________________ Date: ___________ Date: _____________ Roberts Bros. Coal Co., Inc. By: ___________________________ Title: __________________________ Date: ___________ 3 EX-10.45 6 EXHIBIT 10.45 Amendment 4 Page 1 of 11 EXHIBIT 10.45 AMENDMENT TO CONTRACT THIS AMENDMENT is entered into, effective as of January 1, 1995, by and between Louisville Gas and Electric Company (hereinafter referred to as "Buyer"), whose address is: 220 W. Main Street, Louisville, Kentucky 40202 and Shawnee Coal Company (hereinafter referred to as "Seller"), whose address is: 4205 Hillsboro Road, Nashville, Tennessee 37215 and Roberts Bros. Coal Co., Inc. (also hereinafter referred to as "Seller") whose address is: 1690 Columbia School House Road, P.O. Box 1223, Madisonville, Kentucky 42431. In consideration of the agreements herein contained, the parties hereto agree as follows: 1.0 RELEASE OF 1994 EARLY TERMINATION RIGHTS Buyer agrees not to exercise its right to terminate the Agreement as of December 31, 1994 under Section 11 of the Coal Supply Agreement heretofore entered into by the parties, dated August 9, 1989, as amended by Amendment Nos. 1, 2 and 3 thereto (hereinafter referred to as the "Agreement"). 2.0 AMENDMENTS The Agreement is hereby further amended as follows: 2.1 Section 1.1 TERM set forth in the Agreement is amended to read in its entirety as follows: "1.1 TERM. Except for specific effective dates described in specific sections herein, the term of this Agreement shall commence on March 1, 1989 and shall continue until and including December 31, 1996. Prior to October 1, 1996, Buyer and Seller each shall have the right to propose to the other in writing an extension of the term of this Agreement or the parties' entry into a new coal supply agreement. In such case, the parties will negotiate all the terms and conditions (including, but not limited to, price and quantity) of such extension or new agreement. If the parties do not reach an agreement in writing prior to the end of the term of this Agreement, then this Agreement automatically shall terminate on December 31, 1996. Neither party will have any obligation to enter into any such extension or new agreement. 2.2 Article 2.1 ANNUAL QUANTITY set forth in the Agreement is amended to read in its entirety as follows: Amendment 4 Page 2 of 11 "2.1 ANNUAL QUANTITY. Except as adjusted under Section 2.3, Seller shall sell and deliver and Buyer shall purchase and accept delivery of the following annual tonnages ("Annual Quantity"). Amendment 4 Page 3 of 11 Year Reduction in Coal This Amendment Annual Quantity (Tons) - ---- -------------------------------- ---------------------- 1989 ___________ 364,000 1990 ___________ 364,000 1991 ___________ 700,000 1992 ___________ 1,300,000 1993 ___________ 1,125,000 1994 ___________ 1,215,000 1995 115,000 1,100,000 1996 215,000 1,000,000 2.3 Section 2.3 NOTIFICATION is amended to read in its entirety as follows: "2.3 NOTIFICATION. By December 1 of each Agreement year, Buyer shall specify by written notice to Seller the monthly quantities to be delivered in the following Agreement year." 2.4 Section 4.1 QUALITY set forth in the Agreement is amended to read in its entirety as follows: "4.1 QUALITY. The coal delivered hereunder shall conform to the following specifications on an "as received" basis. Guaranteed Monthly Rejection Limits Specification Weighted Average (per shipment) - -------------------------------------------------------------------------------- BTU/lb. min. 11,500 < 10,850 Moisture max. 8.25 lbs./MMBtu > 12.00 lbs./MMbtu Ash max. 10.80 lbs./MMBtu > 13.00 lbs./MMbtu Sulfur max. 2.90 lbs./MMBtu > 3.30 lbs./MMBtu < 1.80 lbs./MMBtu Chlorine max. 0.20 lbs./MMBtu > 0.20 lbs./MMBtu Flourine max. 0.006 lbs./MMBtu > 0.010 lbs./MMBtu Nitrogen max. 1.20 lbs./MMBtu > 1.50 lbs./MMBtu Ash/Sulfur Ratio min. 2.6:1 < 2.5:1 Size: (3" x 0"): Top size (inches)* max. 3" > 3" Fines (% by wgt) passing 1/4 inch screen max. 40% > 45% Amendment 4 Page 4 of 11 % by Weight: Volatile max. 38 > 38 Volatile min. 29 < 29 Fixed Carbon max. 50 > 50 Fixed Carbon min. 30 < 40 Grindability (HGI) min. 55 < 50 Slagging Factor** max. 2 > 2.0 Fouling Factor*** max. 1 > 1.0 ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857) REDUCING ATMOSPHERE Initial Deformation min. 2000 min. 1940 Softening (H=W) min. 2100 min. 2035 Softening (H=1/2 W) min. 2200 min. 2085 Fluid min. 2300 min. 2190 OXIDIZING ATMOSPHERE Initial Deformation min. 2350 min. 2300 Softening (H=W) min. 2400 min. 2330 Softening (H=1/2 W) min. 2500 min. 2425 Fluid min. 2525 min. 2490 * 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 per cent (40%) by weight of coal that will pass through a screen having circular perforations one-quarter (1/4) of an inch in diameter. ** Slagging Factor (Rs)=(B/A) x (Percent Sulfur by WeightDry) *** Fouling Factor (Rf)=(B/A) x (Percent Na2O by Weight Dry) The Base Acid Ration (B/A) is herein defined as: BASE ACID RATIO (B/A) = (Fe2O3 + CaO + MgO + Na2O + K2O ------------------------------ (SiO2 + Al2O3 + T102) Note: As used herein > means greater than; < means less than. Amendment 4 Page 5 of 11 2.5 Section 5.3 FREEZE CONDITIONING set forth in the Agreement is amended to read in its entirety as follows: "5.3 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 rail cars specified by Buyer with side release agent approved by Buyer. The price for each such requested chemical treatment shall be an amount equal to Seller's cost of materials applied on a per gallon basis for each application of freeze conditioning agent or side release agent, as the case may be. Seller shall invoice Buyer for all such treatment which occurred in a calendar month by the fifteenth of the following month; and payment shall be mailed by the 20th of such following month or within five days after receipt of Seller's invoice, whichever is later. 2.6 Section 6.1 PRICE set forth in the Agreement is amended to read in its entirety as follows: "6.1 PRICE. (a) Subject to subsection 6.1(b), the base price ("Base Price") of the coal to be sold hereunder will be firm and will be $.97000 per MMBTU. (b) Notwithstanding the provisions of subsection 6.1(a) above, the Base Price shall not include any MMBTUs to the extent that the actual Monthly Weighted Average for BTU/LB exceeds 11,750. For example, if the Monthly Weighted Average BTU/LB is 11,800 and 100,000 tons of coal were unloaded that month, then the Base Price would be $2,279,500 (100,000 tons X 2,000 lbs/ton X 11,750 BTU/lb X $.97/MMBTU). 2.7 Section 6.2 PRICE REVIEW set forth in the Agreement is deleted in its entirety. 2.8 Section 6.3 QUALITY PRICE ADJUSTMENTS set forth in the Agreement is amended to read in its entirety as follows: "6.3 QUALITY PRICE DISCOUNTS. The Base Price is based on coal meeting or exceeding the Guaranteed Monthly Weighted Average specifications as set forth in Section 4.1. 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 4.1 as determined pursuant to Section 5.2, subject to the provisions set forth below. The discount values used are: Amendment 4 Page 6 of 11 DISCOUNT $/MMBTU -------- BTU/LB. 0.2604 DISCOUNT $/LB./MMBTU ----------- SULFUR 0.1232 ASH 0.0083 MOISTURE 0.0016 Notwithstanding the foregoing, for each specification each month, there shall be no discount if the actual Monthly Weighted Average meets the applicable minimum or maximum set forth below. However, if the actual Monthly Weighted Average fails to meet such applicable minimum or maximum, then the discount shall apply and shall be calculated based upon the difference between the actual Monthly Weighted Average AND THE GUARANTEED MONTHLY WEIGHTED AVERAGE as shown on Exhibit B attached hereto. MINIMUM ------- BTU/LB 11,250 MAXIMUM -------- LB/MMBTU SULFUR 3.10 ASH 12.20 MOISTURE 9.56 2.9 Section 6.4 PAYMENT CALCULATION set forth in the Agreement is amended to read in its entirety as follows: "6.4 PAYMENT CALCULATION. Exhibit B SAMPLE COAL PAYMENT CALCULATIONS 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. 2.10 Section 8.1 FORCE MAJEURE set forth in the Agreement is amended to read in its entirety as follows: "8.1 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 Amendment 4 Page 7 of 11 Agreement due to acts of God, war, riots, civil insurrection ,acts of the public enemy, strikes, lockouts, fires, floods or earthquakes, or other similar occurrences, which are beyond the reasonable control and without the fault or negligence of the party affected thereby, notwithstanding their foreseeability, 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 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. 2.11 Section 9 CHANGES set forth in the Agreement is amended in part so that the last sentence thereof is deleted. 2.12 Section 10.1 FORM AND PLACE OF NOTICE set forth in the Agreement is amended in part so that the Buyer's address is: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, Kentucky 40232 Attention: Manager, Coal Supply and Roberts Bros. Coal Co., Inc.'s address is: Roberts Bros. Coal Co., Inc. 1690 Columbia School House Road P.O. Box 1223 Madisonville, Kentucky 42431 Amendment 4 Page 8 of 11 2.13 Section 11 EARLY TERMINATION set forth in the Agreement is amended to read in its entirety as follows: "Section 11. EARLY TERMINATION. The parties recognize that conditions not now foreseen could arise in which either Buyer or Seller, whether for economic or other compelling reasons, would desire to terminate this Agreement, in whole or in part, in advance of the expiration date. Accordingly, it is agreed that for whatever reason, each party shall have the right of early termination, in whole or in part, of its rights and obligations under this Agreement, subject to the provisions of this Agreement. The party desiring to exercise its right of early termination shall give written notice thereof to the other party and pay the price for early termination as described herein. Notice may be given by either party no later than three (3) months before the end of any Agreement year, and this Agreement will be terminated at the end of such year. The price paid for such early termination shall be $2.75 times the minimum tonnage remaining from the effective date of termination until December 31, 1996. 2.14 Section 14 DISPUTES set forth in the Agreement is deleted in its entirety. 3.0 STATUS OF AGREEMENT As amended herein, the Agreement shall continue in full force and effect. 4.0 FORM OF EXECUTION AND DELIVERY This Amendment may be executed in multiple counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same document. Transmittal by telecopier of an executed copy of this Amendment shall constitute a valid and binding execution and delivery of this Amendment. IN WITNESS WHEREOF, the parties hereto have executed this Amendment on the day and year below written, but effective as of the day and year first set forth above. Shawnee Coal Company Louisville Gas and Electric Company By: ________________________ By: _________________________ Title: ________________________ Title: _________________________ Date: ________________________ Date: _________________________ Amendment 4 Page 9 of 11 Roberts Bros. Coal Co., Inc. By: ________________________ Title: ________________________ Date: ________________________ Amendment 4 Page 10 of 11 EXHIBIT B SAMPLE COAL PAYMENT CALCULATIONS TOTAL EVALUATED COAL COSTS FOR CONTRACT NO. 08901877 FOR CONTRACTS SUPPLIED FROM MULTIPLE "ORIGINS", EACH "ORIGIN" WILL BE CALCULATED INDIVIDUALLY SECTION I. BASE DATA 1) Base F.O.B. price per ton: $___22.31____/ton 1a) Tons of coal delivered: ____________tons 2) Guaranteed average heat content: ___11,600____ B.T.U./LB. 2r) As received monthly avg. heat content: _____________B.T.U./LB. 2a) Energy delivered in M.M.B.T.U.: _____________B.T.U./LB. [(Line 1a)"2,000 lb./ton"(Line 2__)] *MMBTU/1,000,000 BTU [( )*2,000 lb./ton*( )] *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 __290________ LBS./MMBTU 3r) As received monthly avg. sulfur _____________ LBS./MMBTU 4) Guaranteed monthly avg. max. ash __10.80_______ LBS./MMBTU 4r) As received monthly avg. ash _____________ LBS./MMBTU 5) Guaranteed monthly avg. max. moisture __8.25________ LBS./MMBTU 5r) As received monthly avg. moisture ______________ LBS./MMBTU SECTION II. DISCOUNTS Assign a (*) to all discounts to five (5) decimal places) 6d) B.T.U./LB.: If line 2r is less than 11,260 BTU/lb. {1*[(line 2r)/(line 2)]} * 50.2804/MMBTU {1*[( )/( )]} * $0.2604 = $____________/MMBTU 7d) SULFUR: If line 3r is greater than 3.1 lbs./MMBTU [(line 3r)-(Line 3)] * $0.1232/lb sulfur [( )*( )] * $0.1232 = $____________/MMBTU Amendment 4 Page 11 of 11 8d) ASH: If line 4r is greater than 12.20 lbs./MMBTU [(line 4r)*(line 4)] * $0.0083/lb.ash. [( )*( )] * $0.0083 = $____________/MMBTU 9d) MOISTURE: If line 6r is greater than 9.58 lbs./MMBTU [(line 5r)*(line 5)] * $0.0016)lb moisture [( )*( )] * $0.0018 = $____________/MMBTU 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 = $__________/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) $___________ + $_________ = $__________ EX-10.46 7 EXHIBIT 10.46 CONTRACT NO. 93-255-026 EXHIBIT 10.46 COAL SUPPLY AGREEMENT This is a coal supply agreement (the "Agreement") dated January 1, 1994 between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West Main Street, Louisville, Kentucky 40202 ("Buyer") and PEABODY COALSALES COMPANY, a Delaware corporation, 1951 Barrett Court, P.O. Box 1996, Henderson, Kentucky 42420 ("Seller"). RECITAL Peabody Development Company and Buyer entered into a Contract dated December 18, 1991 (as amended by Amendment 1 dated September 1, 1992) (the "Original Contract") for the sale of coal by Peabody Development Company to Buyer. The Original Contract was assigned to Seller by Assignment dated March 1, 1993. AGREEMENTS The parties hereto agree as follows: SECTION 1. GENERAL The Original Contract is hereby terminated as of December 31, 1993. Thereafter, 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 Subject to Section 8.2, the term of this Agreement shall commence on January 1, 1994 and shall continue through December 31, 1999. Buyer shall have the right, but not the obligation, to renew this Agreement for up to five (5) additional one year periods, such right to be exercised by notice in writing to Seller no later than forty-five (45) days prior to the beginning of the year in question. Buyer's right to renew this Agreement is subject to the parties' reaching an agreement on the Base Price for the renewal period. SECTION 3. QUANTITY Section 3.1 BASE QUANTITY. Except as adjusted under Section 3.3, Seller shall sell and deliver and Buyer shall purchase and accept delivery of the following annual base quantity of coal ("Base Quantity"): YEAR BASE QUANTITY (TONS) ---- -------------------- 1994 1,100,000 1995 1,100,000 1996 1,100,000 1997 1,100,000 1998 1,100,000 1999 1,100,000 Section 3.2 DELIVERY SCHEDULE. Except as provided in the last sentence of this Section 3.2, by December 1 of each year, Buyer shall specify in writing to Seller the quantities to be delivered in each month of the following year. Subject to Section 3.3, such quantities shall be shipped in accordance with such schedule. Time is of the essence with respect to the schedule so established; and failure by Seller to deliver in a timely fashion shall constitute a material breach within the meaning of Section 16 of this Agreement. This Section 3.2 fully applies to 1994 deliveries except that Buyer shall have until ten (10) business days after this Agreement becomes fully executed to so specify such monthly delivery schedule for 1994. Section 3.3 ADJUSTMENTS. Buyer shall have the right to change the monthly delivery schedule and the Base Quantity as follows: Buyer may change the quantity to be delivered during each calendar month pursuant to the monthly delivery schedule by giving written notice to Seller 75 days before the beginning of said month. However, the total quantity for each calendar year may not be either more than 1,375,000 tons or less than 825,000 tons. Buyer also has the option to discuss with Seller quantities greater than 1,375,000 tons subject to availability and agreement on price. SECTION 4. SOURCE Section 4.1 SOURCE. Subject to Section 4.4 hereof, the coal sold hereunder, including coal purchased from third parties, shall be supplied from Peabody Coal Company's Lynnville Mine, #5, #6, and #7 seams, Warrick and Spencer Counties, Indiana. The source is described with particularity in Exhibit A "Coal Property" attached hereto and made a part hereof (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. Seller agrees and warrants that it will cause to have at the Coal Property adequate machinery, equipment and other facilities to produce, 3 prepare and deliver coal in the quantity and of the quality required by this Agreement. Seller further agrees that it will cause the operation and maintenance of such machinery, equipment and facilities in accordance with good mining practices so as to efficiently and economically produce, prepare and deliver such coal. Seller agrees that Buyer is not providing any capital for the purchase of such machinery, equipment and/or facilities and that Seller shall operate and maintain same at its sole expense, including all required permits and licenses. Seller hereby allocates to this Agreement sufficient reserves of coal meeting the quality specifications hereof and lying on or in the Coal Property so as to fulfill the quantity requirements hereof. Section 4.3 NON-DIVERSION OF COAL. Seller agrees and warrants that it will not, without Buyer's express prior written consent, use or sell coal from the Coal Property in a way that will reduce the economically recoverable balance of coal in the Coal Property to an amount less than that required to be supplied to Buyer hereunder. Section 4.4 SUBSTITUTE COAL. Notwithstanding the above representations and warranties, Seller shall have the right to supply coal hereunder produced from any of the following mines ("Substitute Coal"): (1) Peabody Coal Company's Ken Mine, #9, #11, #13 seams, Ohio County, Kentucky (2) Peabody Coal Company's Martwick Mine, #9, #11 seams, Muhlenberg County, Kentucky (3) Peabody Coal Company's Camp Complex, #9, #11 seams, Union County, Kentucky (4) Pyramid Mining Inc.'s Patriot and Goshen Mines (the "Pyramid Mines"), #9, #11, #12 seams, Henderson and Ohio Counties, Kentucky 4 subject to the following quantity limitations: (a) In each six-month period throughout the term of this Agreement (i.e., January 1 to June 30 and July 1 to December 31), the Substitute Coal supplied hereunder shall not exceed 50,000 tons or 10% of the total tonnage delivered hereunder during such six-month period, whichever is less. For Substitute Coal delivered hereunder in excess of this quantity limitation (a) ("Excess Substitute Coal"), the Base Price shall be reduced pursuant to Section 8.1. (b) In each calendar month throughout the term of this Agreement, the Substitute Coal produced from the Camp Complex and supplied hereunder shall not exceed a quantity equivalent to that contained in five (5) individual barge loads. (c) The Pyramid Mines may be used as a source of supply during 1994 only and only with the approval of Buyer. Buyer shall not be obligated to accept Substitute Coal beyond quantity limitations (b) and (c) set forth above. 5 SECTION 5. DELIVERY 5.1 GENERAL. At Buyer's option, the coal shall be delivered either all by barge, all by rail, or some portion by barge and some portion by rail where such loading facilities currently exist. 5.2 RAIL DELIVERY. For coal produced from the Coal Property which Buyer designates to be delivered by rail, such coal shall be delivered F.O.B. Destination. Title to and risk of loss respecting such coal will pass to Buyer and the coal will be considered to be delivered when it is unloaded at Buyer's designated destination point. At Buyer's request, Seller shall treat (or have treated) any rail shipment of coal hereunder with a freeze conditioning agent (Shur-Coal No. 615 or equivalent approved by Buyer) in order to maintain coal handling characteristics during shipment. If requested by Buyer, Seller shall also treat (or have treated) any rail cars specified by Buyer with a side release agent (Shur-Coal No. 615 or equivalent approved by Buyer.) The price for each such requested chemical treatment shall be an amount equal to Seller's cost of materials on a per gallon basis for each application of freeze conditioning agent or side release agent, as the case may be. Seller shall invoice Buyer for all such treatment which occurred 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. If Seller delivers Substitute Coal under Section 4.4 hereof by rail from the Pyramid Mines ("Pyramid Rail Coal"), then the coal shall be delivered to Buyer F.O.B. railcar at the Pyramid rail loading facility at Bixby, Kentucky on the Paducah & Louisville Railway (the "Pyramid Rail Delivery Point"). Seller may deliver Pyramid Rail Coal at a location different from the Pyramid 6 Rail 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 Pyramid Rail 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 or custody. Seller shall comply with the applicable provisions of Buyer's rail contractor's tariff. 5.3 BARGE DELIVERY. For coal produced from the Coal Property which Buyer designates to be delivered by barge, the coal shall be delivered to Buyer F.O.B. barge at the Yankeetown dock at mile point 772.5 on the Ohio River (the "Barge Delivery Point"). Seller may deliver coal produced from the Coal Property at a location different from the Barge 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 of coal sold will pass to Buyer and the coal will be considered to be delivered when loaded into barges at the loading dock. Buyer or its contractor shall furnish suitable barges in accordance with a delivery schedule provided by Buyer to Seller. Seller shall 7 arrange and pay for all costs of transporting the coal from the mines to the loading docks and loading and trimming the coal into barges to the proper draft and the proper distribution within the barges. Buyer shall arrange for transporting the coal by barge from the loading dock to its generating station(s) and shall pay for the cost of such transportation. For delays caused by Seller in handling the scheduling of shipments with Buyer's barging contractor, Seller shall be responsible for any demurrage or other penalties assessed by said barging contractor (or assessed by Buyer) which accrue at the Barge Delivery Point, including the demurrage, penalties for loading less than normal full-load tonnage for Buyer's barge carrier's individual barge style and type (an average of approximately 1,500 tons per barge), or other penalties assessed for barges not loaded in conformity with applicable requirements. Buyer shall cause Seller to be given notice of such applicable requirements and reasonable advance notice of any changes in such applicable requirements. Buyer shall be responsible to deliver barges in as clean and dry condition as practicable. Seller shall require of the loading dock operator that the barges and towboats provided by Buyer or buyer's barging contractor be provided convenient and safe berth free of wharfage, dockage and port charges; that while the barges are in the care and custody of the loading dock, all U.S. Coast Guard regulations and other applicable laws, ordinances, rulings, and regulations shall be complied with, including adequate mooring and display of warning lights; that any water in the cargo boxes of the barges be pumped out by the loading dock operator prior to loading; that the loading operations be performed in a workmanlike manner and in accordance with the reasonable loading requirements of Buyer and Buyer's barging contractor; and that the 8 loading dock operator carry landing owners or wharfinger's insurance with basic coverage of not less than $300,000.00 and total of basic coverage and excess liability coverage of not less than $1,000,000.00, and provide evidence thereof to Buyer in the form of a certificate of insurance from the insurance carrier or an acceptable certificate of self-insurance with requirement for 30 days advance notification of Buyer in the event of termination of or material reduction in coverage under the insurance. If Seller delivers Substitute Coal hereunder pursuant to Section 4.4 hereof, the respective Barge Delivery Points shall be as follows: MINE NAME LOAD OUT RIVER MILE POINT --------- -------- ----- ---------- Camp Complex Uniontown Ohio 842.9 Ken Ken Green 97.7 Martwick Gibralter Green 85.9 Pyramid (Patriot) Demao Green 31.5 Pyramid (Goshen) Rockport Green 94.8 and all the provisions set forth in this Section 5.3 hereinabove shall apply. SECTION 6. QUALITY Section 6.1 SPECIFICATIONS. The coal produced from the Coal Property and delivered hereunder shall conform to the following specifications on an "as received" basis: LYNNVILLE MINE Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) -------------------------------------------------------------------------- BTU/LB. min. 10,950 < 10,850 ------ ------ 9 MOISTURE max. 12.91 lbs/MMBTU > 14.0 ----- ----- ASH max. 8.00 lbs/MMBTU > 9.0 ----- ----- SULFUR max. 2.90 lbs/MMBTU > 3.3 ----- ----- SULFUR min. 1.8 lbs/MMBTU < 1.8 ----- ----- CHLORINE max. 0.07 lbs/MMBTU > 0.08 ----- ----- FLUORINE max. 0.013 lbs/MMBTU > 0.013 ----- ----- NITROGEN max. 1.50 lbs/MMBTU > 1.60 ----- ----- ASH/SULFUR RATIO min. 2.5:1 < 2.5:1 ----- ----- Size (3" x 0"): Top size (inches) max. 3"x0" > 3"x0" ----- ----- Fines (% by wgt) Passing 1/4" screen max. 40% > 45% ----- ----- % BY WEIGHT: VOLATILE max. 34.5 > 35.0 ----- ----- VOLATILE min. 33.5 < 33.0 ----- ----- FIXED CARBON max. 44 > 45 ----- ----- FIXED CARBON min. 40 < 40 ----- ----- GRINDABILITY (HGI) min. 53 < 50 ----- ----- BASE ACID RATIO (B/A) SLAGGING FACTOR* max. 2.0 > 2.0 ----- ----- FOULING FACTOR** max. 0.5 > 0.5 ----- ----- ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) ---------------------------------------- REDUCING ATMOSPHERE ------------------- Initial Deformation min. 1910 min. 1875 ----- ----- Softening (H=W) min. 1930 min. 1900 ----- ----- Softening (H=1/2W) min. 1975 min. 1950 ----- ----- Fluid min. 2120 min. 2050 ----- ----- OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2300 min. 2200 ----- ----- Softening (H=W) min. 2325 min. 2300 ----- ----- Softening (H=1/2W) min. 2340 min. 2350 ----- ----- Fluid min. 2400 min. 2400 ----- ----- 10 If Seller delivers Substitute Coal under Section 4.4 hereof, the Substitute Coal produced from the following mines and delivered hereunder shall conform to the following specifications on an "as received" basis: KEN MINE -------- Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) --------------------------------------------------------------------- BTU/LB. min. 11,750 < 11,500 ------ ------ MOISTURE max. 8.94 lbs/MMBTU > 11.0 ----- ------ ASH max. 6.97 lbs/MMBTU > 8.0 ----- ------ SULFUR max. 2.8 lbs/MMBTU > 3.0 ----- ------ SULFUR min. 1.8 lbs/MMBTU < 1.8 ----- ------ CHLORINE max. 0.03 lbs/MMBTU > 0.05 ----- ------ FLUORINE max. 0.013 lbs/MMBTU > 0.013 ----- ------ NITROGEN max. 1.40 lbs/MMBTU > 1.60 ----- ------ ASH/SULFUR RATIO min. 2.5:1 < 2.5:1 ----- ------ Size (3" x 0"): Top size (inches) max. 3"x0" > 3" ----- ----- Fines (% by wgt) Passing 1/4" screen max. 40% > 45% ----- ----- % BY WEIGHT: VOLATILE max. 36.50 > 37 ------ ----- VOLATILE min. 34 < 32 ------ ----- FIXED CARBON max. 46 > 46.5 ------ ----- FIXED CARBON min. 42 < 41 ------ ------ GRINDABILITY (HGI) min. 52 < 50 ------ ------ BASE ACID RATIO (B/A) SLAGGING FACTOR* max. 2.0 > 2.0 ------ ------ FOULING FACTOR** max. 0.5 > 0.5 ------ ------ ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) ---------------------------------------- 11 REDUCING ATMOSPHERE ------------------- Initial Deformation min. 1960 min. 1900 ----- ------ Softening (H=W) min. 2000 min. 1950 ----- ------ Softening (H=1/2W) min. 2050 min. 1975 ----- ------ Fluid min. 2190 min. 2100 ----- ------ OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2300 min. 2200 ------ ------ Softening (H=W) min. 2325 min. 2280 ------ ------ Softening (H=1/2W) min. 2340 min. 2300 ------ ------ Fluid min. 2400 min. 2375 ------ ------ MARTWICK MINE ------------- Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) ------------------------------------------------------------------ BTU/LB. min. 11,750 < 11,500 ------ ------ MOISTURE max. 9.02 lbs/MMBTU > 11.0 ------ ------ ASH max. 7.49 lbs/MMBTU > 9.0 ------ ------ SULFUR max. 2.46 lbs/MMBTU > 2.7 ------ ------ SULFUR min. 1.8 lbs/MMBTU < 1.8 ------ ------ CHLORINE max. 0.04 lbs/MMBTU > 0.05 ------ ------ FLUORINE max. 0.013 lbs/MMBTU > 0.013 ------ ------ NITROGEN max. 1.45 lbs/MMBTU > 1.50 ------ ------ ASH/SULFUR RATIO min. 2.5:1 < 2.5:1 ------ ------ Size (3" x 0"): Top size (inches) max. 3"x0" > 3"x0" ------ ------ Fines (% by wgt) Passing 1/4" screen max. 45% > 50% ------ ------ % BY WEIGHT: VOLATILE max. 36 > 36.5 ------ ------ VOLATILE min. 34 < 33 ------ ------ FIXED CARBON max. 46 > 46.5 ------ ------ 12 FIXED CARBON min. 43 < 40 ------ ------ GRINDABILITY (HGI) min. 52 < 50 ------ ------ BASE ACID RATIO (B/A) SLAGGING FACTOR* max. 2.0 > 2.0 ------ ------ FOULING FACTOR** max. 0.5 > 0.5 ------ ------ ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) ---------------------------------------- REDUCING ATMOSPHERE ------------------- Initial Deformation min. 2010 min. 1900 ------ ------ Softening (H=W) min. 2060 min. 1950 ------ ------ Softening (H=1/2W) min. 2120 min. 1975 ------ ------ Fluid min. 2355 min. 2100 ------ ------ OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2440 min. 2200 ----- ------ Softening (H=W) min. 2495 min. 2280 ----- ------ Softening (H=1/2W) min. 2425 min. 2300 ----- ------ Fluid min. 2575 min. 2375 ----- ------ CAMP COMPLEX ------------ Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) ------------------------------------------------------------------- BTU/LB. min. 11,400 < 11,300 ------ ------ MOISTURE max. 10.53 lbs/MMBTU > 12.0 ------ ------ ASH max. 8.65 lbs/MMBTU > 10.0 ------ ------ SULFUR max. 2.54 lbs/MMBTU > 2.8 ------ ------ SULFUR min. 1.8 lbs/MMBTU < 1.8 ------- ------ CHLORINE max. 0.10 lbs/MMBTU > 0.10 ------ ------ FLUORINE max. 0.013 lbs/MMBTU > 0.013 ------ ------ 13 NITROGEN max. 1.40 lbs/MMBTU > 1.60 ------ ------ ASH/SULFUR RATIO min. 2.5:1 < 2.5:1 ------ ------ Size (3" x 0"): Top size (inches) max. 3"x0" > 3"x0" ------ ------ Fines (% by wgt) Passing 1/4" screen max. 45% > 50% ------ ------ % BY WEIGHT: VOLATILE max. 36.5 > 37 ------ ------ VOLATILE min. 34 < 32 ------ ------ FIXED CARBON max. 44 > 45 ------ ------ FIXED CARBON min. 42 < 41 ------ ------ GRINDABILITY (HGI) min. 52 < 50 ------ ------ BASE ACID RATIO (B/A) SLAGGING FACTOR* max. 2.0 > 2.0 ------ ----- FOULING FACTOR** max. 0.5 > 0.5 ------ ----- ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) ---------------------------------------- REDUCING ATMOSPHERE ------------------- Initial Deformation min. 1900 min. 2200 ------ ------ Softening (H=W) min. 1950 min. 2280 ------ ------ Softening (H=1/2W) min. 1975 min. 2300 ------ ------ Fluid min. 2100 min. 2375 ------ ------ OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2300 min. 2275 ------ ------ Softening (H=W) min. 2330 min. 2300 ------ ------ Softening (H=1/2W) min. 2425 min. 2400 ------ ------ Fluid min. 2490 min. 2450 ------ ------ PYRAMID MINES ------------- 14 Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) ---------------------------------------------------------------- BTU/LB. min. 11,200 < 11,000 ------ ------ MOISTURE max. 12.50 lbs/MMBTU > 13.0 ------ ------ ASH max. 8.45 lbs/MMBTU > 9.0 ------ ------ SULFUR max. 2.50 lbs/MMBTU > 2.6 ------ ------ SULFUR min. 1.80 lbs/MMBTU < 1.8 ------- ------ CHLORINE max. 0.07 lbs/MMBTU > .09 ------ ------ FLUORINE max. 0.013 lbs/MMBTU > 0.013 ------ ------ NITROGEN max. 1.40 lbs/MMBTU > 1.80 ------ ------ ASH/SULFUR RATIO min. 2.5:1 < 2.5:1 ------ ------ Size (3" x 0"): Top size (inches) max. 3" > 3" ------ ------ Fines (% by wgt) Passing 1/4" screen max. 40% > 40% ------ ------ % BY WEIGHT: VOLATILE max. 39 > 40 ------ ------ VOLATILE min. 31 < 30 ------ ------ FIXED CARBON max. 57 > 58 ------ ------ FIXED CARBON min. 33 < 32 ------ ------ GRINDABILITY (HGI) min. 48 < 45 ------ ------ BASE ACID RATIO (B/A) SLAGGING FACTOR* max. 2.0 > 2.0 ------ ------ FOULING FACTOR** max. 0.5 > 0.5 ------ ------ ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) ---------------------------------------- REDUCING ATMOSPHERE ------------------- Initial Deformation min. 2100 min. 2000 ----- ------ Softening (H=W) min. 2205 min. 2100 ----- ------ Softening (H=1/2W) min. 2300 min. 2200 ----- ------ Fluid min. 2400 min. 2300 ----- ------ 15 OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2450 min. 2350 ----- ------ Softening (H=W) min. 2500 min. 2400 ----- ------ Softening (H=1/2W) min. 2560 min. 2500 ----- ------ Fluid min. 2600 min. 2525 ----- ------ * Slagging Factor (R(s))=(B/A) x (Percent Sulfur by Weight(Dry)) ** Fouling Factor (R(f))=(B/A) x (Percent Na(2)0 by Weight(Dry)) The Base Acid Ratio (B/A) is herein defined as: (Fe(2)0(3) + Ca0 + Mg0 + Na(2)0 + K(2)0) BASE ACID RATIO (B/A) = ------------------------------------------------ (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, as the case may be. 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 16 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 exceeds the price of such coal under this Agreement (as adjusted under Section 8.3 for coal of the 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, etc., the estimated weight of such materials shall be deducted from the weight of that shipment. Section 6.4 SUSPENSION AND TERMINATION. If one or more shipments of the coal sold hereunder fails to meet one or more of the 17 rejection limits set forth in Section 6.1 (i.e., are rejectable) in any 2 months in a 6 month period, or if 9 barge shipments in a 30 day period are rejectable by Buyer, or if Buyer receives at generating station(s) 2 unapproved rail shipments which are rejectable in any 30 day period, Buyer may upon notice confirmed in writing and sent to Seller by certified mail, suspend future shipments except shipments already loaded into barges and/or railcars. Seller shall, within 10 days, provide Buyer with reasonable assurances that subsequent monthly deliveries of coal shall be within the rejection limits set forth in Section 6.1. If Seller fails to provide such assurances within said 10 day period, Buyer may terminate this Agreement by giving written notice of such termination at the end of the 5 day period. A waiver of this right for any one period by Buyer shall not constitute a waiver for subsequent periods. If Seller provides such assurances to Buyer's reasonable satisfaction, shipments hereunder shall resume and any tonnage deficiencies resulting from suspension may be made up at Buyer's sole option. Buyer shall not unreasonably withhold its acceptance of Seller's assurances, or delay the resumption of shipment. If Seller, after such assurances, fails to meet the Guaranteed Monthly Weighted Averages for 1 month within the next 6 months or if 6 individual barge shipments, 2 barge lot loads, or 2 rail shipments are rejectable within one month during such six month period, then Buyer may terminate this Agreement 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 18 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 A.S.T.M. specifications. Samples for analyses shall be taken by any reliable and industry accepted standard, mutually 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 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. 19 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 by Seller, 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, and one part ("Referee Sample") shall be retained by Buyer for a period of 30 days. Seller shall be given timely and routine copies of all analyses made by Buyer. 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, 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 within 30 days of the date of sampling, 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. The analysis of the Independent Lab shall control to the extent provided in this Section 7.2. A dispute shall be deemed not to exist and Buyer's analysis shall prevail if the analysis of a sample made by the Independent Lab differs from the analysis of Buyer by an amount equal to or less than: (i) 0.50% moisture or (ii) 0.50% ash on a dry basis or (iii) 100 Btu/lb. on a dry basis, or (iv) 0.10% sulfur on a dry basis. The cost of the analysis made by the Independent Lab shall be borne by Seller if Buyer's analysis prevails and by Buyer if the analysis of the Independent Lab prevails. 20 SECTION 8. PRICE Section 8.1 PRICE. Subject to Section 8.2, the base price (the "Base Price") of the coal produced from the Coal Property to be sold hereunder will be firm and will be determined by the year in which the coal is delivered in accordance with the following schedule: BASE PRICE (IN $/MMBTU) ----------------------- FOB DESTINATION YEAR FOB BARGE (BY RAIL) ---- --------- -------------------- 1994 .92100 1.01689 1995 .94863 1.04740 1996 .97709 1.07882 1997 1.00640 1.11119 1998 1.03659 1.14452 1999 1.06769 1.17886 The Base Price is inclusive of all federal, state, municipal and local taxes, fees and costs of any kind whether arising from government law, rule, regulation or otherwise, including, without limitation, all costs of conforming to federal and state mining and reclamation laws, rules and regulations and all other and/or additional mining and operating costs and expenses incurred during the term of this Agreement. No price adjustment shall be made under this Agreement for costs occasioned by changes in laws, rules, regulation, or the like or in any taxes or other governmental imposition(s) enacted or promulgated after the date of this Agreement. The Base Price shall be firm and not subject to adjustment except as provided in this Section 8. 21 For coal produced from the Coal Property and delivered F.O.B. Destination (by rail), the Base Price is based on current rail transportation costs from the Coal Property to the destination point. If such rail transportation costs increase or decrease, then the Base Price shall be adjusted immediately so that 100 percent of the additional costs or the savings, as the case may be, resulting from such transportation costs increase or decrease, shall be passed through to the Buyer. Buyer shall have the right to participate in the negotiations between Seller and the rail transportation company concerning any relevant rail transportation agreement. If Seller delivers Substitute Coal hereunder pursuant to Section 4.4 hereof and within the quantity limitations set forth in Section 4.4, the Base Price shall be as follows: BASE PRICE (IN $/MMBTU) ----------------------- CAMP COMPLEX PYRAMID MINES YEAR MARTWICK KEN ---- -------------- --- 1994 .95960 .93750 1995 .98839 .96563 1996 1.01804 .99459 1997 1.04858 1.02443 1998 1.08004 1.05516 1999 1.11244 1.08682 For Excess Substitute Coal (as defined in Section 4.4(a)), the Base Price of such coal shall be reduced to the Base Price of coal produced from the Coal Property (F.O.B. Barge) (in $/MMBTU) set forth in this Section 8.1 above; and Buyer further shall be credited with the amount by which Buyer's cost (in $/MMBTU) of transporting Excess Substitute Coal from the applicable Delivery Point to 22 the destination point exceeds Buyer's cost of transporting coal produced from the Coal Property from the applicable Barge Delivery Point to the destination point. The coal quality specifications which shall be applied to determine quality price adjustments for Excess Substitute Coal shall be the specifications set forth in Section 6.1 for the mine from which the Excess Substitute Coal was produced. Section 8.2 PRICE REVIEW. The Base Price and Quality Price Adjustment provisions in Section 8 of this Agreement shall be subject to review for any reason at the request of either party, for revision(s) to become effective on January 1, 1997. The party requesting such a review shall give written notice of its request to the other party on or before October 1, 1996. The parties then shall negotiate an agreement on new Base Prices between October 1 and December 1. If the parties do not reach an agreement on new Base Prices by December 1, then this Agreement will terminate as of December 31, 1996 without liability due to such termination for either party. Section 8.3 QUALITY PRICE ADJUSTMENTS. The Base Price is based on coal having the Guaranteed Monthly Weighted Average specification as set forth in Section 6.1. Quality price adjustments (discounts and/or premiums) shall be made to reflect variances from the Guaranteed Monthly Weighted Averages set forth in Section 6.1 as determined pursuant to Section 7.2. The discount and premium values used are: DISCOUNT PREMIUM $/MMBTU $/MMBTU ------- ------- BTU/LB. 0.2604 0.1354 23 DISCOUNT PREMIUM $/LB./MMBTU $/LB./MMBTU ----------- ----------- SULFUR 0.1232 0.1084 ASH 0.0083 0.0073 MOISTURE 0.0016 0.0014 The sulfur premium shall be based on lbs/MMBTU below the Guaranteed Monthly Weighted Average Maximum. However, there shall be no sulfur premium for coal with sulfur content below the Guaranteed Monthly Weighted Average minimum Section 8.4 PAYMENT CALCULATION. Exhibit B attached hereto shows the methodology for calculating the coal payment and quality price adjustments for the month Seller's coal was unloaded by Buyer. SECTION 9. INVOICES, BILLING AND PAYMENT. Section 9.1 Invoices will be sent to LG&E at the following address: Louisville Gas & Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Manager, Coal Supply With a copy to: Louisville Gas & Electric Company 820 West Broadway P. O. Box 32020 Louisville, KY 40232 Attention: Manager, Accounts Payable 24 Section 9.2 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice Buyer at the Base Price, as adjusted by the quality price adjustments, 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 payments to Seller's account at Peabody COALSALES Company, P.O. Box 503099, St. Louis, MO 63150-30999. To make wire transfers contact Boatman's Bank, Account ABA 081000032, wire transfer account 100101223441. 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. 25 SECTION 10. FORCE MAJEURE Section 10.1 GENERAL 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 or earthquakes, 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 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. During any period in which Buyer's ability to perform hereunder is affected by a force majeure event, Buyer shall not purchase any coal from any other sellers from whom Buyer's ability to purchase is similarly affected by such force majeure event unless contractually 26 committed to do so at the beginning of the force majeure event; and further shall purchase from Seller under this Agreement at least a pro-rata portion (on a per ton basis) of its total contractual commitments to all sellers from whom Buyer's ability to purchase is similarly affected by such force majeure event in place at the beginning of the force majeure event. Tonnage deficiencies resulting from a force majeure event shall be made up at Buyer's sole option on a reasonable schedule. Section 10.2 ENVIRONMENTAL LAW FORCE MAJEURE. The parties recognize that, during the continuance of this Agreement, legislative or regulatory bodies or the courts may adopt environmental laws, regulations, policies and/or restrictions which will make it impossible or commercially impracticable for Buyer to utilize this or like kind and quality coal which thereafter would be delivered hereunder. If as a result of the adoption of such laws, regulations, policies, or restrictions, or change in the interpretation or enforcement thereof, Buyer decides that it will be impossible or commercially impracticable (uneconomical) for Buyer to utilize such coal, Buyer shall so notify Seller, and thereupon Buyer and Seller shall promptly consider whether corrective actions can be taken in the mining and preparation of the coal at Seller's mine and/or in the handling and utilization of the coal at Buyer's generating station; and if in Buyer's sole judgment such actions will not, without unreasonable expense to Buyer, make it possible and commercially practicable for Buyer to so utilize coal which thereafter would be delivered hereunder without violating any applicable law, regulation, policy or order, Buyer shall have the right, upon the later of 60 days notice to Seller or the effective date of such restriction, to terminate this Agreement 27 without further obligation hereunder on the part of either party. SECTION 11. CHANGES. Buyer may, by mutual agreement with Seller, at any time by written notice pursuant to Section 12 of this Agreement, make changes within the general scope of this Agreement in any one or more of the following: quality of coal or coal specifications, quantity of coal, method or time of shipments, place of delivery (including transfer of title and risk of loss), method(s) of weighing, sampling or analysis and such other provision as may affect the suitability and amount of coal for Buyer's generating stations. If any such changes makes necessary or appropriate an increase or decrease in the then current Base Price per ton of coal, or in any other provision of this Agreement, an equitable adjustment shall be made in: Base Price, whether current or future or both, and/or in such other provisions of this Agreement as are affected directly or indirectly by such change, and the Agreement shall thereupon be modified in writing accordingly. Any claim by the Seller for adjustment under this Section 11 shall be asserted within thirty (30) days after the date of Seller's receipt of the written notice of change, it being understood, however that Seller shall not be obligated to proceed under this Agreement as changed until an equitable adjustment has been agreed upon. The parties agree to negotiate promptly and in good faith to agree upon the nature and extent of any equitable adjustment. In the event Seller and Buyer are unable to mutually agree on the changes requested by Buyer under this Section 11, then this Agreement shall continue in full force and effect without taking into account such requested changes. 28 SECTION 12. NOTICES Section 12. 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: If to Buyer: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, Kentucky 40232 Attn: Manager, Coal Supply 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: Peabody COALSALES Company 1951 Barrett Court Suite 200 P.O. Box 1996 Henderson, Kentucky 42420-1996 Attn: Vice-President, Sales Section 12.2 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. 29 Section 12.3 ELECTRONIC DATA TRANSMITTAL. Seller hereby agrees, at Seller's cost, to electronically transmit shipping notices and/or other data to Buyer in a format acceptable to and established by Buyer upon Buyer's request. Buyer shall provide Seller with the appropriate format and will inform Seller as to the electronic data requirements at the appropriate time. SECTION 13. EARLY TERMINATION. Each party hereto shall have the right of early termination for any reason or no reason, in whole or in part, of its rights and obligations under this Agreement as follows: The party desiring to exercise its right of early termination shall give written notice thereof to the other party and pay the price for early termination as described herein. Notice may be given by either party no later than four (4) months before the end of any calendar year; and this Agreement will be terminated at the end of such year. The price paid for such early termination shall be $3.50 times the Base Quantity remaining under this Agreement from the effective date of the early termination until either the effective date of the next price change which may occur pursuant to the next price review right set forth in Section 8.2 (i.e., January 1, 1997) or the termination of this Agreement (i.e., January 1, 2000), as applicable. For example, if Seller terminates this Agreement effective January 1, 1996, then Seller would owe Buyer $3,850,000 under this Section 13. If this Agreement remains in effect after the price review and Seller then terminates this Agreement effective January 1, 1998, then Seller would owe Buyer $7,700,000 under this Section 13. SECTION 14. RIGHT TO RESELL. Buyer shall have the unqualified right to sell all or any of the coal purchased under this Agreement. 30 SECTION 15. INDEMNITY AND INSURANCE Section 15.1 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. Section 15.2 INSURANCE. Seller agrees to maintain 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 31 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 16. 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 notice describing such breach and stating its intention to terminate this Agreement no sooner than 30 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 17. 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. 32 SECTION 18. DOCUMENTATION AND RIGHT OF AUDIT Seller shall maintain all records and accounts pertaining to payments, quantities, quality analyses, source, and proposed revisions to the Base Price 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 19. 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 60-1.4(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 20. COAL PROPERTY INSPECTIONS AND INJURIES TO REPRESENTATIVES Upon reasonable notice Buyer reserves the right to have its representative(s) visit and 33 inspect all aspects of the Coal Properties including the loading facilities, scales, sampling system(s), wash plant facilities, and mining equipment at any time during the term of this Agreement. Seller and Buyer, respectively, assume full risk for damage or injury to their representatives or employees when such representatives or employees are on the premises of the other party in connection with the exercise of any rights or the performance of any obligations hereunder except where the damage or injury is caused by the negligence of the other party. Each party agrees that, to the extent permitted by law, it will indemnify and hold the other party harmless against all loss or liability resulting from any such damage or injury occurring on the premises of the other party except where such damage or injury is caused by the negligence of the other party. SECTION 21. MISCELLANEOUS Section 21.1 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 21.2 HEADINGS. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning of interpretation of this Agreement. Section 21.3 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 21.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement shall be 34 cumulative and in addition to other remedies provided under this Agreement or by law or in equity. Section 21.5 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 21.6 BINDING EFFECT. This Agreement shall bind and inure to the benefit of the parties and their successors and assigns. Section 21.7 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 21.8 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 21.9 AMENDMENTS. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by both parties 35 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 COMPANY By: __________________________ Title: __________________________ Date: __________________________ PEABODY COALSALES COMPANY By: __________________________ Title: __________________________ Date: __________________________ 36 EX-12 8 EXHIBIT 12 EXHIBIT 12 LOUISVILLE GAS AND ELECTRIC COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Thousands of $)
1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Earnings: Income before cumulative effect of a change in accounting principle per statements of income . . . . . . . . . . . . . . . . . . . $ 61,689 $ 90,535 $ 73,793 $ 94,643 $ 83,450 Add: Federal income taxes - current. . . . . . . . . . 30,926 42,091 13,785 35,490 24,966 State income taxes - current. . . . . . . . . . . 7,726 12,954 3,140 8,425 8,232 Deferred Federal income taxes - net . . . . . . . (950) 4,712 20,441 17,207 13,142 Deferred State income taxes - net . . . . . . . . 956 226 8,470 6,085 4,475 Investment tax credit - net . . . . . . . . . . . (4,619) (7,821) (5,033) (11,472) (1,964) Fixed charges . . . . . . . . . . . . . . . . . . 44,665 49,640 52,196 55,171 56,061 ------- ------- ------- ------- ------- Earnings. . . . . . . . . . . . . . . . . . . . 140,393 192,337 166,792 205,549 188,362 ------- ------- ------- ------- ------- Fixed Charges: Interest Charges per statements of income . . . . 42,856 47,496 49,833 52,680 53,663 Add: Interest income (1) . . . . . . . . . . . . . . - - 4 98 251 One-third of rentals charged to operating expense (2). . . . . . . . . . . . . 1,809 2,144 2,359 2,393 2,147 ------- ------- ------- ------- ------- Fixed charges . . . . . . . . . . . . . . . . $ 44,665 $ 49,640 $ 52,196 $ 55,171 $ 56,061 ------- ------- ------- ------- ------- Ratio of Earnings to Fixed Charges . . . . . . . . . . 3.14 3.87 3.20 3.73 3.36 ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- NOTES: (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 EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report dated January 30, 1995, included in this Form 10-K, into the Company's previously filed Registration Statement No. 33-13427. Louisville, Kentucky Arthur Andersen LLP March 24, 1995 EX-24 10 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, 1994 (the 1994 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 1994 Form 10-K and to any and all amendments to such 1994 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 1st day of March 1995. 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 Owsley Brown II Charles A. Markel III - ------------------------------------ ---------------------------------- Owsley Brown II, Director Charles A. Markel III, Principal Financial Officer S. Gordon Dabney Anne H. McNamara - ------------------------------------ ---------------------------------- S. Gordon Dabney, Director Anne H. McNamara, Director M. L. Fowler T. Ballard Morton, Jr. - ------------------------------------ ---------------------------------- M. L. Fowler, Principal T. Ballard Morton, Jr., Director Accounting Officer Gene P. Gardner Dr. Donald C. Swain - ------------------------------------ ---------------------------------- Gene P. Gardner, Director Dr. Donald C. Swain, Director STATE OF KENTUCKY ) ) ss. COUNTY OF JEFFERSON ) On this 1st day of March 1995, 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, 1996 Kathryn M. Carpenter, Notary Public State of Kentucky at Large EX-27 11 EXHIBIT 27
UT 1,000 12-MOS DEC-31-1994 DEC-31-1994 PER-BOOK 1,656,034 50,681 207,971 51,904 0 1,966,590 424,334 (1,751) 193,895 616,478 0 116,716 662,862 0 0 0 0 0 0 0 570,534 1,966,590 759,075 39,922 608,113 648,035 111,040 (9,864) 101,176 42,856 58,320 5,828 52,492 53,500 41,357 180,881 0 0 Includes Common Stock Expense of $836. Represents Unrealized Loss on Marketable Securities, Net of Income Taxes. Includes ($3,369) for Cumulative Effect of Change in Accounting for Post-Employment Benefits, Net of Income Taxes.
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