-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HlwbmqVlBqGkEApElUGzJwLPKtpZfcQrqp4chwnRjJKx0LbJrTOTODgVOnld0prM YgBTiv3nUADdj/LbLwY0OA== 0000912057-96-005235.txt : 19960328 0000912057-96-005235.hdr.sgml : 19960328 ACCESSION NUMBER: 0000912057-96-005235 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960327 SROS: NASD SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: LOUISVILLE GAS & ELECTRIC CO /KY/ CENTRAL INDEX KEY: 0000060549 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 610264150 STATE OF INCORPORATION: KY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-02893 FILM NUMBER: 96538935 BUSINESS ADDRESS: STREET 1: 220 W MAIN ST STREET 2: P O BOX 32010 CITY: LOUISVILLE STATE: KY ZIP: 40232 BUSINESS PHONE: 5026272000 MAIL ADDRESS: STREET 1: 220 WEST MAIN ST CITY: LUUISVILLE STATE: KY ZIP: 40232 10-K405 1 10-K405 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 --------------------------- FORM 10-K [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended DECEMBER 31, 1995 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, New York Stock Exchange Series due July 1, 2002, 7 1/2% SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: 5% Cumulative Preferred Stock, $25 Par Value $5.875 Cumulative Preferred Stock, Without Par Value Auction Rate Series A Preferred Stock, Without Par Value (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/ . No . ----- ---- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] --- As of February 29, 1996, the aggregate market value of the registrant's voting stock held by non-affiliates was $16,882,700 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 13, 1996, is incorporated by reference into Part III of this Form 10-K. TABLE OF CONTENTS PART I PAGE Item 1. Business................................................... 1 General.................................................. 1 Electric Operations...................................... 4 Gas Operations........................................... 6 Regulation and Rates..................................... 7 Construction Program and Financing....................... 8 Coal Supply.............................................. 9 Gas Supply............................................... 10 Environmental Matters.................................... 11 Labor Relations.......................................... 11 Employees................................................ 11 Item 2. Properties................................................. 12 Item 3. Legal Proceedings.......................................... 13 Item 4. Submission of Matters to a Vote of Security Holders........ 14 Executive Officers of the Company................................... 14 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters...................................... 16 Item 6. Selected Financial Data.................................... 16 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition....................... 16 Item 8. Financial Statements and Supplementary Data................ 26 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................. 49 PART III Item 10. Directors and Executive Officers of the Registrant (a)..... 50 Item 11. Executive Compensation (a)................................. 50 Item 12. Security Ownership of Certain Beneficial Owners and Management (a)....................................... 50 Item 13. Certain Relationships and Related Transactions (a)......... 50 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................................. 50 Signatures.......................................................... 67 Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges...... 68 Exhibit 23 - Consent of Independent Public Accountants.............. 69 (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 272,000 customers and electricity to approximately 346,000 customers in Louisville and adjacent areas in Kentucky. The Company's service area covers approximately 700 square miles in 17 counties and has an estimated population of 800,000. Included in this area is the Fort Knox Military Reservation, to which the Company transports gas and provides electric service, but which maintains its own distribution systems. The Company also provides gas service in limited additional areas. The Company's coal-fired electric generating plants, which are all equipped with systems to remove sulfur dioxide, produce most of the Company's electricity; the remainder is generated by a hydroelectric power plant and combustion turbines. Underground natural gas storage fields help the Company provide economical and reliable gas service to customers. In August 1990, the Company and LG&E Energy Corp. (Energy Corp.) implemented a corporate reorganization pursuant to a mandatory share exchange whereby each share of outstanding common stock of the Company was exchanged on a share-for-share basis for the common stock of Energy Corp. The reorganization created a corporate structure that gives the holding company the flexibility to take advantage of opportunities to expand into other businesses while insulating the Company's utility customers and senior security holders from 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 had been subject to numerous reviews by the Public Service Commission of Kentucky (Kentucky Commission or Commission). On December 8, 1995, the Commission approved a settlement agreement filed by the Company and all intervenors in the Trimble County proceedings, including various consumer interest groups and government agencies, that in effect, resolves all of the regulatory and legal issues related to the appropriate ratemaking treatment to exclude 25% of the Trimble County costs from customer rates. The Company has sold a 25% ownership interest in the Unit. For a more detailed discussion of the proceedings relating to Trimble County and the sale of 25% of the Unit, see Electric Operations and Notes 14 and 15 of Notes to Financial Statements under Item 8. The Clean Air Act Amendments of 1990 (the Act) 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 $22 million to date and anticipates incurring capital expenditures of approximately $8 million in 1996 for remedial measures necessary to meet the Act's requirements for nitrogen oxides. The overall financial impact of the legislation on the Company is expected to be minimal. The Company is well-positioned in the market to be a "clean" power provider without the large capital expenditures that are expected to be incurred by many other utilities. For a more detailed discussion of the Clean Air Act and other environmental issues, see -1- Environmental Matters under this Item, Item 3, Item 7, and Note 13 of the Notes to Financial Statements under Item 8. 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. Pursuant to the Energy Policy Act, the Federal Energy Regulatory Commission (FERC) earlier this year issued a Notice of Proposed Rulemaking on Open Access Non-discriminatory Transmission Services and a Supplemental Notice of Proposed Rulemaking on Stranded Investment (collectively, the Mega-NOPR). The Mega-NOPR is intended, among other things, to create a vigorous wholesale electric market by requiring transmission providers to offer open access to their transmission systems. The Company is supportive of proposals to increase competition at all levels of the electric power market and intends to pursue opportunities created by a more competitive market. 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; a major realignment and formation of new business units, and a modification of its organizational structure. Effective December 15, 1995, LG&E Energy Corp. modified its organizational structure. Changes are designed to facilitate decision making, improve response to customers and better align operating units with the changing competitive marketplace. Four operating divisions were established: Distribution Services Division - which includes the distribution resources of the Company, is responsible for expanding and developing the distribution businesses and investing in enhanced service offerings behind the customer's meter. Gas Marketing Division - primarily consists of the businesses of LG&E Natural Inc. (a subsidiary of LG&E Energy Corp.), which markets gas throughout the United States and Canada. Power Marketing Division - includes LG&E Power Marketing Inc. (LPM), is responsible for project development and the marketing and sale of wholesale power throughout the United States. Power Generation Division - which includes the generation resources of the Company, LG&E Power Inc. and LG&E International Inc., has responsibility for all utility and non-utility power plant operations, asset management, and development functions both domestically and internationally. The Company's wholesale power will continue to be marketed and brokered by LG&E Power Marketing Inc. (LPM), a wholly-owned subsidiary of LG&E Energy Corp. LPM 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. During 1995, its first full year of operations, LPM sold or brokered 1.8 million megawatt-hours of power in 30 states. This -2- volume of activity placed LPM among the five largest marketers of wholesale energy in 1995 and the largest seller affiliated with a regulated electric utility. LPM is predicting that the market for electric energy will expand and its revenues and contributions to corporate income will increase in future years. 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. 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. During the last quarter of 1995, the Company negotiated a five-year transportation agreement with Tennessee Gas Pipeline Company (Tennessee) to become the Company's second natural gas pipeline transporter. The agreement with Tennessee becomes effective November 1, 1996. For many years, Texas Gas Transmission Corporation (Texas Gas) has been the sole provider of gas transport services to the Company. For further discussion, see Gas Supply. On July 31, 1995, Vantage Consulting, Inc. released its report on the Kentucky Commission's management audit of the Company. This comprehensive audit, which began in September 1994, included more than 300 interviews and over 875 requests for information. This was the second management audit of the Company mandated by the Kentucky Commission, the first being completed in 1986. The overall audit findings were very favorable and recognized that the Company has become an innovative industry leader that has implemented many performance improvements to lower costs, improve efficiency, prepare for increased competition, and increase its focus on customer satisfaction. For further discussion, see Regulation and Rates. -3- For the year ended December 31, 1995, 75% of total operating revenues was derived from electric operations and 25% 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.......................... $201,357 $107,762 $309,119 44% Commercial........................... 160,571 38,161 198,732 29 Industrial........................... 110,800 17,430 128,230 18 Public authorities................... 53,861 8,679 62,540 9 -------- -------- -------- ---- Total service revenues............... 526,589 172,032 698,621 100% Refund - Trimble County Settlement (28,300) (a) - (28,300) ---- -------- -------- -------- ---- Total-ultimate consumers 498,289 172,032 670,321 Sales for resale..................... 37,471 - 37,471 Gas transportation-net............... - 7,821 7,821 Miscellaneous........................ 6,577 1,273 7,850 -------- -------- -------- Total............................. $542,337 $181,126 $723,463 -------- -------- -------- -------- -------- --------
(a) See Note 14 of Notes to Financial Statements under Item 8. See Note 16 of Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 1995. Electric Operations The sources of electric operating revenues and the volumes of sales for the three years ended December 31, 1995, were as follows:
1995 1994 1993 ---- ---- ---- ELECTRIC OPERATING REVENUES (Thousands of $): Residential........................... $201,357 $194,145 $195,273 Small commercial and industrial....... 73,074 70,916 70,106 Large commercial...................... 87,497 84,931 84,231 Large industrial...................... 110,800 108,004 104,506 Public authorities.................... 53,861 53,191 52,183 Refund - Trimble County Settlement (28,300) - - -------- -------- -------- Total-ultimate consumers........... 498,289 511,187 506,299 Sales for resale...................... 37,471 42,720 58,959 Miscellaneous......................... 6,577 5,039 4,952 -------- -------- -------- Total.............................. $542,337 $558,946 $570,210 -------- -------- -------- -------- -------- -------- ELECTRIC SALES (Thousands of kwh): Residential........................... 3,415,225 3,204,330 3,230,463 Small commercial and industrial....... 1,112,130 1,073,152 1,056,977 Large commercial...................... 1,802,035 1,729,668 1,696,686 Large industrial...................... 3,023,543 2,874,411 2,736,269 Public authorities.................... 1,113,063 1,085,741 1,053,928 ---------- ---------- ---------- Total-ultimate consumers........... 10,465,996 9,967,302 9,774,323 Sales for resale...................... 2,000,607 2,315,311 3,299,510 ---------- ---------- ---------- Total.......................... 12,466,603 12,282,613 13,073,833 ---------- ---------- ---------- ---------- ---------- ----------
At December 31, 1995, the Company had 346,099 electric customers. -4- 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 1995 was approximately .85 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 Thursday, August 17, 1995, the Company set a record local peak load of 2,357 Mw, when the temperature at the time of peak reached 94 DEG. F (average for the day was 86 DEG. F). The 1994 maximum local peak load of 2,219 Mw occurred on Wednesday, June 15, when the temperature at time of peak was 95 DEG. F (average for the day was 85 DEG. 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 29, 1996, the Company owned steam and combustion turbine generating facilities with a capacity of 2,512 Mw and an 80 Mw hydroelectric facility on the Ohio River. See Item 2, Properties. The Company is a participating owner with 14 other electric utilities of Ohio Valley Electric Corporation whose primary customer is the Portsmouth Area uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio. The Company has direct interconnections with 11 utility companies in the area and has agreements with each interconnected utility for the purchase and sale of capacity and energy. The Company also has agreements with an increasing number of entities throughout the United States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission system. 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 $83 million since 1987 in its investigation and research with regard to possible health effects posed by exposure to electric and magnetic fields. -5- Gas Operations The sources of gas operating revenues and the volumes of sales for the three years ended December 31, 1995, were as follows:
1995 1994 1993 ---- ---- ---- GAS OPERATING REVENUES (Thousands of $): Residential........................... $107,762 $110,553 $112,508 Commercial............................ 38,161 40,474 43,568 Industrial............................ 17,430 27,956 28,310 Public authorities.................... 8,679 12,930 13,846 -------- -------- -------- Total-ultimate consumers........... 172,032 191,913 198,232 Gas transportation-net................ 7,821 6,759 5,147 Miscellaneous......................... 1,273 1,457 1,536 -------- -------- -------- Total.............................. $181,126 $200,129 $204,915 -------- -------- -------- -------- -------- -------- GAS SALES (Millions of cu. ft.): Residential..................... 24,242 22,935 24,330 Commercial...................... 9,885 9,450 10,308 Industrial...................... 5,188 7,505 7,817 Public authorities.............. 2,423 3,268 3,515 -------- -------- -------- Total-ultimate consumers....... 41,738 43,158 45,970 Gas transported................. 12,241 6,854 5,249 -------- -------- -------- Total.......................... 53,979 50,012 51,219 -------- -------- -------- -------- -------- --------
At December 31, 1995, the Company had 272,135 gas customers. The Company has underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers. Reflecting the changing nature of the gas business, a number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through the Company's distribution system. Generally, transportation of natural gas for the Company's customers does not have an adverse effect on earnings because of the offsetting decrease in gas supply expenses. Transportation rates are designed to make the Company economically indifferent as to whether gas is sold or merely transported. The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 DEG. F. During 1995, the maximum day gas sendout was 454,000 Mcf, occurring on December 9, when the average temperature for the day was 9 DEG. F. Supply on that day consisted of 208,000 Mcf from purchases, 199,000 Mcf delivered from underground storage, and 47,000 Mcf transported for industrial customers. For further discussion, see Gas Supply. Under FERC Order No. 636, pipelines may recover costs associated with the transition to and implementation of this order from pipeline customers, including the Company. During 1995, the Company paid and began recovering from its customers approximately $4.8 million in transition costs under Order No. 636. It is estimated that about $1.4 million in additional transition costs will be incurred by the Company during 1996 and about $1.3 million in 1997, and these costs are also expected to be recovered from customers. See Note 13 of Notes to Financial Statements under Item 8 for further discussion of FERC Order No. 636. -6- 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 14 of Notes to Financial Statements under Item 8. Increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all of the Company's electric customers by means of the Company's fuel adjustment clause. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals for the purpose of additional examination and transfer of the then current fuel adjustment charge or credit to the base charges. The Commission also requires that electric utilities, including the Company, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities. The Company's gas rates contain a gas supply clause (GSC), whereby increases or decreases in the cost of gas supply are reflected in the Company's rates, subject to approval of the Kentucky Commission. The GSC procedure prescribed by order of the Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters. On December 8, 1995, the Commission approved a settlement agreement filed by the Company and all intervenors in the Trimble County proceedings, including various consumer interest groups and government agencies, that, in effect, resolves all the regulatory and legal issues related to the appropriate ratemaking treatment to exclude 25% of the Trimble County plant costs from customer rates. See Note 14 of Notes to Financial Statements under Item 8 for further discussion of this matter. On July 31, 1995, Vantage Consulting, Inc. released its report on the Kentucky Commission's management audit of the Company. This comprehensive audit, which began in September 1994, included more than 300 interviews and over 875 requests for information. This was the second management audit of the Company mandated by the Kentucky Commission, the first being completed in 1986. The overall audit findings were very favorable and recognized that the Company has become an innovative industry leader that has implemented many performance improvements to lower costs, improve efficiency, prepare for increased competition, and increase its focus on customer satisfaction. The audit report identified additional improvement opportunities and contained a series of recommendations which should assist the Company with its future plans. It is estimated that implementation of the audit recommendations could provide the Company with as much as $11 -7- million in annual gross savings. However, incremental costs will be incurred to achieve the full benefits of the recommendations and the ultimate savings will be realized over the long-term. 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. On April 6, 1995, the Commission approved, with modifications, an environmental cost recovery surcharge that increased electric revenues by $3.2 million in 1995 and will increase revenues by an estimated $5.7 million in 1996. The Company, the Kentucky Attorney General, and the Kentucky Industrial Utility Customers have filed appeals on certain issues included in the April 6 order. See Rates and Regulation under Item 7 for a further discussion of the surcharge. 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. 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 and reliability to meet the electric and gas needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. The Company's estimates of its construction expenditures can vary substantially due to numerous items beyond the Company's control, such as changes in rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations. During the five years ended December 31, 1995, gross property additions amounted to $476 million. Internally generated funds for the five year period were sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 18% of total utility plant at December 31, 1995, and consisted of $356 million for electric properties and $120 -8- million for gas properties. Gross retirements during the same period were $82 million, consisting of $67 million for electric properties and $15 million for gas properties. At December 31, 1995, the Company's embedded cost of long-term debt was 6.3% and its ratio of earnings to fixed charges was 3.99. See Exhibit 12. For a further discussion of construction expenditures and financing, see Liquidity and Capital Resources under Item 7. Coal Supply Over 90% of the Company's present electric generating capacity is coal-fired, the remainder being made up of a hydroelectric plant and combustion turbine peaking units fueled by natural gas and oil. Coal will be the predominant fuel used by the Company in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies. The Company has no nuclear generating units and has no plans to build any in the foreseeable future. In January 1996, the Company bought out the last year of its three year contract with Andalex Resources, Inc. at a cost of $3.5 million. The Company has filed an application with the Kentucky Commission to recover the cost of the buyout through the fuel adjustment clause. As a result of the buyout of the coal contract, the Company's customers will realize a net savings in excess of $1 million. The Company has entered into coal supply agreements with various suppliers for coal deliveries for 1996 and beyond. The Company normally augments its coal supply agreements with spot market purchases which, during 1995, 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, 1995, a coal inventory of approximately 600,000 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%-4.5% range. The abundant supply of this relatively low priced coal, combined with present and future desulfurization technologies, is expected to enable the Company to continue to provide adequate electric service in a manner acceptable under existing environmental laws and regulations. Coal for the Company's Mill Creek plant is delivered by rail and barge. Deliveries to the Cane Run and Trimble County plants are by rail and barge, respectively. The average delivered cost of coal purchased by the Company, per ton and per million Btu, for the periods shown were as follows:
1995 1994 1993 ------ ------ ------ Per ton........................... $23.68 $25.27 $26.58 Per million Btu................... 1.04 1.10 1.14
This downward trend in the delivered cost of coal is expected to continue through 1996. -9- Gas Supply Prior to the implementation of FERC Order No. 636, the Company had purchased natural gas and pipeline transportation services from Texas Gas Transmission Corporation (Texas Gas). The Company now purchases only transportation services from Texas Gas and purchases natural gas from many other sources under contracts for varying periods of time. See Management's Discussion and Analysis, Future Outlook, under Item 7. 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 1995, the Company paid Texas Gas and began recovering from its customers approximately $4.8 million in transition costs. It is estimated that about $1.4 million in additional transition costs will be incurred by the Company during 1996 and about $1.3 million in 1997, and these costs are also expected to be recovered from customers. These transition costs are billed by Texas Gas pursuant to orders issued by FERC in transition cost regulatory proceedings in which the Company is a party. Pursuant to these FERC orders, no additional transition costs are expected to be billed after 1997. During 1995, the Company participated in several regulatory proceedings at FERC. These proceedings resolved, subject to final FERC approval, issues in Texas Gas' rate case as well as transition cost issues from the implementation of Order No. 636 by Texas Gas. The Company does not expect significant regulatory initiatives by Texas Gas at FERC during 1996. The Company transports on the Texas Gas System under No-Notice Service (NNS) and Firm Transportation (FT) rates. In 1995, the Company made two important modifications to its transportation agreements with Texas Gas. During the winter months, the Company has 184,900 MMBtu (180,390 mcf) per day in NNS. During 1995, the Company's summer NNS level was reduced from 135,000 MMBtu (131,708 Mcf) per day to 111,000 MMBtu (108,293 Mcf), and 24,000 MMBtu (23,415 Mcf) per day was converted to FT service. Each of these NNS and FT agreements with Texas Gas expire in equal portions in 1998, 2000, and 2001. Each agreement includes a unilateral five year roll-over provision exercisable at the Company's option. The Company also has a transportation agreement with Texas Gas which provides for 30,000 MMBtu (29,268 Mcf) per day in FT service throughout the year. The primary term of this FT agreement expired October 31, 1995, subject to a year-to-year termination by either party. During 1995, the Company provided the required one year prior written notice to terminate this FT agreement effective November 1, 1996. During the last quarter of 1995, the Company negotiated a five year transportation agreement with Tennessee Gas Pipeline Company (Tennessee) for 30,000 MMBtu (29,268 Mcf) per day in Firm Transportation service under Tennessee's Rate FT-A. This agreement with Tennessee becomes effective November 1, 1996. For many years, Texas Gas had been the sole provider of gas transport services to the Company. The Company also has a portfolio of supply arrangements with various suppliers in order to meet its firm sales obligations. These gas supply arrangements include pricing provisions which are -10- market-responsive. These firm supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve the Company's customers. The Company operates five underground gas storage fields with a current working gas capacity of 14.6 million Mcf. Gas is purchased and injected into storage during the summer season and is then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter heating season. The estimated maximum deliverability from storage during the early part of the 1994-1995 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 $2.62 in 1995, $2.78 in 1994, and $2.91 in 1993. Environmental Matters Protection of the environment is a major priority for the Company. The Company engages in a variety of activities within the jurisdiction of federal, state, and local regulatory agencies. Those agencies have issued the Company permits for various activities subject to air quality, water quality, and waste management laws and regulations. For the five year period ending with 1995, expenditures for pollution control facilities represented $90 million or 19% of total construction expenditures. The cost of operating and maintaining scrubber-related facilities amounted to $21 million in 1995 and $22 million in 1994. The Company's anticipated capital expenditures for 1996 to comply with environmental laws are approximately $8 million. See Note 13 of Notes to Financial Statements under Item 8 for a discussion of specific environmental proceedings affecting the Company. Labor Relations On December 8, 1995, members of the International Brotherhood of Electrical Workers Local 2100 ratified a new three year collective bargaining agreement with the Company, which covers approximately 1,600 employees. The contract provides wage and employment protection for employees participating in the Company's continuous improvement initiative, greater workforce flexibility to help the Company respond to growing competition, and improved retirement benefits. Employees The Company had 2,594 full-time employees at December 31, 1995. -11- ITEM 2. PROPERTIES. The Company's power generating system consists of the coal-fired units operated at its three steam generating stations. Combustion turbines supplement the system during peak or emergency periods. At February 29, 1996, 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 480,000 1,470,000 ------- Cane Run-near Louisville, Ky. Unit 4........................................... 1962 155,000 Unit 5........................................... 1966 168,000 Unit 6........................................... 1969 240,000 563,000 ------- Trimble County-Bedford, Ky. Unit 1........................................... 1990 371,000 (a) Combustion Turbine Generators (Peaking capability): Zorn............................................... 1969 16,000 Paddy's Run........................................ 1968 43,000 Cane Run........................................... 1968 16,000 Waterside.......................................... 1964 33,000 108,000 ------- --------- 2,512,000 --------- ---------
(a) Amount shown represents the Company's 75% interest in the Unit. See Note 15 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. The Company also owns an 80 Mw hydroelectric generating station located in Louisville, operated under license issued by the FERC. At December 31, 1995, the Company's electric transmission system included 21 substations with a total capacity of approximately 11,026,897 Kva and approximately 651 structure miles of lines. The electric distribution system included 82 substations with a total capacity of approximately 3,193,127 Kva, 3,507 structure miles of overhead lines, 233 miles of underground conduit, and 5,380 miles of underground conductors. The Company's gas transmission system includes 177 miles of transmission mains, and the gas distribution system includes 3,466 miles of distribution mains. The Company operates underground gas storage facilities with a current working gas capacity of approximately 14.6 million Mcf. See Gas Supply under Item 1. In 1990, the Company entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease is for a period of 15 years and is scheduled to expire in June 2005. -12- 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 Trimble County Unit 1 settlement agreement, see Rates and Regulation under Item 7 and Notes 2 and 14 of Notes to Financial Statements under Item 8. Statewide Power Planning On March 14, 1995, the Commission staff issued its report on its review of the Company's 1993 biennial Integrated Resource Plan. The Staff Report specifically found that the Company's plan contained some of the better analyses among those filed by the electric utilities under the Commission's jurisdiction, and presented several suggestions for the Company's consideration when it develops its next plan. By order issued on March 17, 1995, the Commission formally closed its proceeding for the review of the Company's plan. On May 5, 1995, the Commission granted the Company's request that the Commission waive the requirement that the Company file an Integrated Resource Plan during 1995. On July 21, 1995, the Kentucky Commission amended its Integrated Resource Planning regulations to replace the biennial filing requirement with a triennial requirement. The amended regulations also specified that the Company's next Integrated Resource Plan is to be filed 39 months from the effective date of the amended regulation, or October 21, 1998. Environmental For a complete discussion of the Company's environmental issues concerning its Mill Creek and Cane Run generating plants, manufactured gas plant sites, and certain other environmental issues, see Note 13 of Notes to Financial Statements under Item 8. Other In the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against the Company. To the extent that damages are assessed in any of these lawsuits, the Company believes that its insurance coverage is adequate. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company's consolidated financial position or results of operations. -13- ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None -------------------- Executive Officers of the Company.
Effective Date of Election Name Age Position to Present Position ---- --- -------- -------------------------- Roger W. Hale 52 Chairman of the Board and Chief Executive Officer January 1, 1992 Victor A. Staffieri 40 President January 1, 1994 Walter Z. Berger 40 Executive Vice President and Chief Financial Officer February 5, 1996 John R. McCall 52 Executive Vice President, General Counsel and Corporate Secretary July 1, 1994 M. Lee Fowler 59 Vice President and Controller September 1, 1988 Wendy C. Heck 42 Vice President, Information Services January 1, 1994 Chris Hermann 48 Vice President and General Manager, Wholesale Electric Business January 1, 1993 Rebecca L. Holt 36 Vice President, Gas Service Business February 15, 1995 Charles A. Markel III 48 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 23, 1996. There are no family relationships between executive officers of the Company. Mr. Hale, Mr. Fowler, Ms. Heck, Mr. Hermann, and Mr. Markel have been employed for more than five years in executive or management positions with the Company. Prior to election to the position shown in the table, the following executive officers held other positions with the Company since January 1, 1991: Mr. Hale was Chairman of the Board, President and Chief Executive Officer; 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 -14- 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-Finance and Treasurer prior to January 1992, and Senior Vice President and Chief Financial Officer thereafter. Effective January 1993, Mr. Markel was named Corporate Vice President-Finance, and Treasurer of the parent company, LG&E Energy Corp. Prior to election to his current position, Mr. Staffieri was Senior Vice President-Public Policy, and General Counsel of the Company, and prior to November 1992, Senior Vice President, General Counsel and Corporate Secretary. Prior to March 1992, Mr. Staffieri was employed by Long Island Lighting Company and held the position of General Counsel and Secretary. Prior to election to his current position, Mr. Berger was employed by Enron Oil Trading and Transportation and held the position of Vice President, Finance and Business Development. Prior to November 1992, Mr. Berger was Controller for Enron America, Inc., and prior to February 1992, Vice President and Chief Financial Officer for Baker Hughes, Inc. 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, and General Manager, Northern Division-Gas Operations prior to February 1992. -15- 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:
1995 1994 ---- ---- (Thousands of $) First Quarter............. $18,000 $17,500 Second Quarter............ 34,000 17,500 Third Quarter............. 18,000 - Fourth Quarter............ 18,500 18,000
ITEM 6. SELECTED FINANCIAL DATA.
Years Ended December 31 (Thousands of $) --------------------------------------------------------------------------- 1995 1994 1993 1992 1991 ---- ---- ---- ---- ---- Operating Revenues . . . . . . . . . . . $ 723,463 $ 759,075 $ 775,125 $ 700,195 $ 708,706 ----------- ----------- ----------- ----------- ----------- Net Operating Income: Before Unusual Items. . . . . . . . . 138,203 134,393 136,118 125,829 142,730 Trimble County Settlement . . . . . . (16,877) - - - - Non-Recurring Charges . . . . . . . . - (23,353) - - - ----------- ----------- ----------- ----------- ----------- Total Net Operating Income . . . . 121,326 111,040 136,118 125,829 142,730 ----------- ----------- ----------- ----------- ----------- Net Income: Before Unusual Items. . . . . . . . . 100,061 94,423 90,535 73,793 94,643 Trimble County Settlement . . . . . . (16,877) - - - - Non-Recurring Charges, Charitable Foundation, etc.. . . . - (32,734) - - - Cumulative Effect of Accounting Change. . . . . . . . . - (3,369) - - - ----------- ----------- ----------- ----------- ----------- Total Net Income . . . . . . . . . 83,184 58,320 90,535 73,793 94,643 ----------- ----------- ----------- ----------- ----------- Net Income Available for Common Stock . . . . . . . . . . . . . 76,873 52,492 84,554 66,620 85,179 ----------- ----------- ----------- ----------- ----------- Total Assets . . . . . . . . . . . . . . 1,979,490 1,966,590 1,974,584 1,960,860 1,936,909 Long-Term Obligations (including amounts due within one year) . . . . . 662,800 662,800 662,800 686,262 687,662
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 1995, 1994 and 1993 and should be read in connection with the financial statements and notes thereto. -16- Results of Operations Net Income The Company's net income increased $24.9 million for 1995 over 1994 in spite of recording a charge of $28.3 million ($16.9 million after-tax) in 1995 to recognize the effects of the settlement of the long-standing issues surrounding the Company's Trimble County electric generating plant. (See Note 14 of Notes to Financial Statements, Trimble County Generating Plant, under Item 8). In 1994 net income of $58.3 million included the write-off of certain non-recurring items ($23.9 million), the expense of establishing a charitable foundation ($8.9 million), and the adoption of Statement of Financial Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS ($3.4 million). Without consideration of the charges against income in 1995 and 1994 as discussed above, the Company's 1995 net income increased $5.6 million over 1994. This improvement is primarily due to higher retail electric sales during 1995 partially offset by increased purchased power expenses resulting from unplanned power plant outages this summer. In 1994 the Company's net income decreased $32.2 million. This decrease was due to the 1994 write-off of non-recurring items as discussed in the preceding paragraph totaling $36.2 million. Without consideration of the non-recurring charges against income discussed above, the Company's 1994 net income would have increased $3.9 million over 1993. This improvement is primarily a result of increased sales of electricity to retail customers and reduced interest on debt due to favorable refinancing activities in 1993. 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. On December 8, 1995, the Commission approved a settlement agreement filed by the Company and all intervenors in the Trimble County proceedings, including various consumer interest groups and government agencies, that, in effect, resolves all of the regulatory and legal issues related to the appropriate ratemaking treatment to exclude 25% of the Trimble County plant costs from customer rates. Under the settlement, ratepayers are to receive $22 million in refunds, most of which is to be refunded over a five-year period, commencing in 1996, based on a per kilowatt-hour credit. In addition, the Company also agreed to provide $900,000 annually for five years to fund low-income energy assistance programs and to revise the decoupling methodology described in this section in a manner that will reduce revenues collected from residential customers during 1996 and 1997 by a total of approximately $1.8 million. The overall effect of the settlement, which the Company recognized in its entirety in the fourth quarter of 1995, was to reduce electric revenues by $28.3 million and net income by $16.9 million. See Note 14 of Notes to Financial Statements under Item 8 for further discussion. -17- On July 31, 1995, Vantage Consulting, Inc. released its report on the Kentucky Commission's management audit of the Company. This comprehensive audit, which began in September 1994, included more than 300 interviews and over 875 requests for information. This was the second management audit of the Company mandated by the Kentucky Commission, the first being completed in 1986. The overall audit findings were very favorable and recognized that the Company has become an innovative industry leader that has implemented many performance improvements to lower costs, improve efficiency, prepare for increased competition, and increase its focus on customer satisfaction. The audit report identified additional improvement opportunities and contained a series of recommendations which should assist the Company with its future plans. It is estimated that implementation of the audit recommendations could provide the Company with as much as $11 million in annual gross savings. However, incremental costs will be incurred to achieve the full benefits of the recommendations and the ultimate savings will be realized over the long-term. 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. On April 6, 1995, the Commission approved, with modifications, an environmental cost recovery surcharge that increased electric revenues by $3.2 million in 1995 and will increase revenues by an estimated $5.7 million in 1996. The surcharge became effective on May 1, 1995. The Company, the Kentucky Attorney General (KAG) and the Kentucky Industrial Utility Customers (KIUC) filed applications for rehearing on certain issues in the April 6 order. Among other things, the KAG and KIUC requested a reduction of the amounts recoverable by the Company through the surcharge. The Commission denied all motions for rehearing, and appeals are currently pending in Franklin Circuit Court. The amount of refunds that may be ordered, if any, are not expected to have a material adverse effect on the Company's financial position or results of operations. On January 1, 1994, the Company implemented a Commission approved demand side management (DSM) program that the Company, KAG, the Jefferson County Attorney, and representatives of several customer-interest groups had filed with the Commission. Under the agreement, the Company committed up to $3.3 million over three years (from 1994 through 1996) for initial programs that include a residential energy conservation and education program and a commercial conservation audit program. The agreement also provided for a formal collaborative process to develop future DSM programs. The agreement contains a rate mechanism that (1) provides the Company concurrent recovery of DSM program costs, (2) provides an incentive for implementing DSM programs, and (3) allows the Company to recover revenues from lost sales associated with the DSM programs. 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 -18- factor in residential revenue per customer. To the extent that actual revenues are different from the predetermined level of revenues, rates are subsequently adjusted to correct for any over or under recoveries. 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. On December 1, 1995, the Company and the DSM collaborative members filed a plan which would modify the existing programs and add five new programs. The proposed filing would increase the Company's commitment to DSM programs by approximately $4.1 million. The Company expects the Commission to rule on the filing in the second quarter of 1996. In 1993, the Federal Energy Regulatory Commission (FERC) gave final approval for a market-based generation sales tariff and two transmission service tariffs which were filed by the Company. The market-based tariff enables the Company to sell up to 75 Mw of firm generation capacity and an unlimited amount of non-firm power at market-based rates. On July 26, 1995, FERC approved a new network transmission service and a flexible point-to-point transmission service which will provide transmission service to other parties comparable to the transmission service utilized by the Company to serve retail customers. The Company last filed for a rate increase with the Commission in June 1990 based on the test-year ended April 30, 1990. The Commission issued a final order in September 1991 that effectively granted the Company an annual increase in rates of $6.8 million ($6.1 million electric and $.7 million gas). The Commission's order authorized a rate of return on common equity of 12.5%. Revenues A comparison of operating revenues for the years 1995 and 1994, excluding the Trimble County settlement (which reduced electric revenues by $28.3 million), 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 1995 1994 1995 1994 ----- ---- ---- ---- ---- Sales to Ultimate Consumers: Fuel and gas supply adjustments, etc....... $(10,566) $ (841) $(16,940) $ 1,823 Demand side management/decoupling.......... (4,619) 1,853 479 3,997 Environmental cost recovery surcharge...... 3,205 - - - Variation in sales volumes................. 27,382 3,876 (3,420) (12,139) -------- -------- -------- -------- Total................................... 15,402 4,888 (19,881) (6,319) Sales for resale................................ (5,249) (16,239) - - Gas transportation-net.......................... - - 1,062 1,612 Other........................................... 1,538 87 (184) (79) -------- -------- -------- -------- Total................................... $ 11,691 $(11,264) $(19,003) $ (4,786) -------- -------- -------- -------- -------- -------- -------- --------
Electric revenues increased in 1995 mainly because of an increase in sales to ultimate consumers as a result of the warmer summer weather and improved economic conditions in the -19- Company's service territory. Gas revenues decreased as a result of lower gas supply adjustment revenues which reflected the lower cost of natural gas in 1995. 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. 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 $5.6 million (4%) in 1995 due to a decrease in the cost of coal burned ($7.5 million) partially offset by increased generation of 2%. 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%. The average delivered cost per ton of coal purchased was $23.68 in 1995, $25.27 in 1994, and $26.58 in 1993. This downward trend in the delivered cost of coal is expected to continue through 1996. Power purchased increased $7.1 million in 1995 primarily because of increased purchases resulting from unplanned outages at the electric generating plants during the extremely hot summer weather. The decrease of $7.5 million in 1994 was primarily due to less power wheeled for other utilities as a result of milder weather in the region. Gas supply expenses decreased $20.8 million (16%) in 1995 because of the lower cost of net gas supply ($18.7 million) and a decrease in the volume of gas delivered to the distribution system ($2.1 million). 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). The average unit cost per Mcf of purchased gas was $2.62 in 1995, $2.78 in 1994, and $2.91 in 1993. Other operation expenses decreased $1.6 million in 1995, as compared to 1994, primarily as a result of a $6 million credit to expense representing a portion of the proceeds received in a commercial dispute (see the following paragraph for more discussion) and a decrease in expenses ($1.2 million) associated with property damage claims. These decreases were partially offset by an increase in labor related expenses ($3.8 million) and an increase in various administrative expenses ($1.8 million). Maintenance expense increased $3.4 million in 1995 primarily as a result of an increase in repairs at the electric power plants ($4.2 million), partially offset by a decrease in storm damage expenses ($1 million). During 1995, the Company received cash proceeds of $8 million in connection with the settlement of a commercial dispute. Pursuant to a study to determine the proper amount of income to be recognized, the Company recognized $6 million as a reduction of operation expenses. The remaining $2 million was recorded as a reserve for future payments in connection with the dispute. -20- 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. Non-recurring charges in 1994 include the Company's write-off of costs in connection with early retirements and workforce reductions that occurred in 1992 and 1993, costs in connection with property damage claims pertaining to particulate emissions from the Mill Creek electric generating plant, and certain costs previously deferred resulting from adoption of Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS. See Note 3 of Notes to Financial Statements under Item 8. Depreciation and amortization increased in both 1995 and 1994 primarily because of additional depreciable plant in service. Variations in income tax expenses are largely attributable to changes in pre-tax income. Other income and (deductions) increased $1.3 million primarily because of an increase in dividend and interest income from investments. Other income and (deductions) increased $.5 million in 1994 partially due to recognition of a gain on the sale of construction equipment. See Note 9 of Notes to Financial Statements under Item 8 for further detail. Contribution to the Company's charitable foundation reflects the expense associated with establishing a tax-exempt foundation during 1994. Contributions made from this Foundation are not charged against income, and therefore, do not affect the Company's net income. See Note 3 of Notes to Financial Statements under Item 8. Interest charges for 1995 decreased $.9 million primarily due to a reversal of an interest expense reserve resulting from a favorable ruling on certain income tax matters. 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. Since 1993, an immaterial component of interest expense has been the cost associated with interest rate swaps. See Note 4, Financial Instruments, under Item 8 for further discussion. Preferred dividends increased $.5 million in 1995 because of a higher rate associated with the Auction Rate Series. Preferred dividends in 1994 reflect the lower dividends that resulted from the Company's refunding of its $25 million, $8.90 Series with a $5.875 Series in May 1993. See Liquidity and Capital Resources. 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. -21- 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. 1995 Capital Requirements New construction expenditures for 1995 were $93 million compared with $95 million for 1994 and $99 million for 1993. Past Financing Activities During 1995, 1994, and 1993, 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 1995, 1994, and 1993. 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 1995, accounts receivable and accounts payable were higher due to colder weather in the last quarter of the year as compared to 1994. In December 1995, the Company redeemed the outstanding shares of its 7.45% Cumulative Preferred Stock with a par value of $25 per share at a redemption price of $25.75 per share. The Company funded the $22 million redemption with cash generated internally. In April 1995, the Company issued $40 million of Jefferson County, Kentucky, Pollution Control Revenue Bonds, 5.90% Series, due April 15, 2023. The proceeds of the bonds were used to redeem the outstanding 9.25% Series of Pollution Control Bonds due July 1, 2015. 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 $220 million for 1996 and 1997. In addition, 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 1996 and 1997. -22- At December 31, 1995, the Company had unused lines of credit of $160 million for which it pays commitment fees. These credit facilities are scheduled to expire during the year 2000. Management expects to renegotiate them when they expire. To the extent permanent financings are needed in 1996 and 1997, 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 (the Act) 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 $22 million to date and anticipates incurring capital expenditures of approximately $8 million in 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 13, 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 and Related Matters 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. Pursuant to the Energy Policy Act, the FERC earlier this year issued a Notice of Proposed Rulemaking on Open Access Non-discriminatory Transmission Services and a Supplemental Notice of Proposed Rulemaking on Stranded Investment (collectively, the Mega-NOPR). The Mega-NOPR is intended, among other things, to create a vigorous wholesale electric market by requiring transmission providers to offer open access to their transmission systems. The Company is supportive of proposals to increase competition at all levels of the electric power market and intends to pursue opportunities created by a more competitive market. FERC Order No. 636 Under Order No. 636, pipelines may recover costs associated with the transition to and implementation of this order from pipeline customers, including the Company. During 1995, the Company paid and began recovering from its customers approximately $4.8 million in transition costs under Order No. 636. It is estimated that about $1.4 million in additional transition costs will be incurred by the Company during 1996 and about $1.3 million in 1997, and these costs are also -23- expected to be recovered from customers. See FERC Order No. 636 under Note 13 of Notes to Financial Statements under Item 8 for further discussion. FUTURE OUTLOOK Business Realignment Effective December 15, 1995, LG&E Energy Corp. modified its organizational structure. The changes are designed to facilitate decision making, improve response to customers and better align operating units with the changing competitive marketplace. Four operating divisions were established: Distribution Services Division - which includes the distribution resources of Louisville Gas and Electric Company (LG&E), is responsible for expanding and developing the distribution businesses and investing in enhanced service offerings behind the customer's meter. Gas Marketing Division - primarily consists of the businesses of LG&E Natural Inc. (a subsidiary of LG&E Energy Corp.), which markets gas throughout the United States and Canada. Power Marketing Division - includes LG&E Power Marketing Inc. (LPM), is responsible for project development and the marketing and sale of wholesale power throughout the United States. Power Generation Division - which includes the generation resources of LG&E, LG&E Power Inc. and LG&E International Inc., has responsibility for all utility and non-utility power plant operations, asset management, and development functions both domestically and internationally. Wholesale power will continue to be marketed and brokered by LPM, a wholly-owned subsidiary of LG&E Energy Corp. LPM 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. During 1995, its first full year of operations, LPM sold or brokered 1.8 million megawatt-hours of power in 30 states. This volume of activity placed LPM among the five largest marketers of wholesale energy in 1995 and the largest seller affiliated with a regulated electric utility. LPM is predicting that the market for electric energy will expand and its revenues will increase in future years. 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. -24- Tennessee Gas Pipeline Company During the last quarter of 1995, the Company negotiated a five-year transportation agreement with Tennessee Gas Pipeline Company (Tennessee) to become the Company's second natural gas pipeline transporter. The agreement with Tennessee becomes effective November 1, 1996. For many years, Texas Gas Transmission Corporation has been the sole provider of gas transport services to the Company. Union Contract On December 8, 1995, members of the International Brotherhood of Electrical Workers Local 2100 ratified a new three-year collective bargaining agreement with the Company, which covers approximately 1,600 employees. The contract provides wage and employment protection for employees participating in the Company's continuous improvement initiative, greater workforce flexibility to help the Company respond to growing competition, and improved retirement benefits. 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; a major realignment and formation of new business units, and a modification of its organization structure. -25- ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Thousands of $)
Years Ended December 31 --------------------------------------- 1995 1994 1993 ---- ---- ---- Operating Revenues Electric.............................................. $570,637 $558,946 $570,210 Refund - Trimble County Settlement (Note 14) (28,300) - - Gas................................................... 181,126 200,129 204,915 -------- -------- -------- Total operating revenues (Note 1)..................... 723,463 759,075 775,125 -------- -------- -------- Operating Expenses Fuel for electric generation.......................... 138,002 143,602 149,436 Power purchased....................................... 16,830 9,754 17,228 Gas supply expenses................................... 110,738 131,561 139,054 Other operation expenses.............................. 134,655 136,214 136,693 Maintenance........................................... 52,101 48,731 48,414 Non-recurring charges (Note 3)........................ - 38,613 - Depreciation and amortization......................... 85,759 82,519 79,655 Federal and State income taxes (Note 8)............... 47,524 39,922 52,334 Property and other taxes.............................. 16,528 17,119 16,193 -------- -------- -------- Total operating expenses.............................. 602,137 648,035 639,007 -------- -------- -------- Net Operating Income.................................... 121,326 111,040 136,118 Other Income and (Deductions) (Note 9).................. 3,776 2,451 1,913 Contribution to Charitable Foundation - net (Note 3).... - 8,946 - Interest Charges........................................ 41,918 42,856 47,496 -------- -------- -------- Income before Cumulative Effect of a Change in Accounting Principle.................................. 83,184 61,689 90,535 Cumulative Effect of a Change in Accounting for Post-Employment Benefits, net of income taxes of $2,280 (Note 7).................................... - (3,369) - -------- -------- -------- Net Income.............................................. 83,184 58,320 90,535 Preferred Stock Dividends............................... 6,311 5,828 5,981 -------- -------- -------- Net Income Available for Common Stock................... $ 76,873 $ 52,492 $ 84,554 -------- -------- -------- -------- -------- --------
STATEMENTS OF RETAINED EARNINGS (Thousands of $)
Years Ended December 31 -------------------------------------- 1995 1994 1993 ---- ---- ---- Balance January 1....................................... $193,895 $194,903 $178,667 Add net income.......................................... 83,184 58,320 90,535 -------- -------- -------- 277,079 253,223 269,202 -------- -------- -------- Deduct: Cash dividends declared on stock: 5% cumulative preferred........................... 1,075 1,075 1,075 7.45% cumulative preferred........................ 1,527 1,598 1,598 $8.90 cumulative preferred........................ - - 1,113 Auction rate cumulative preferred................. 2,240 1,686 1,322 $5.875 cumulative preferred....................... 1,469 1,469 873 Common............................................ 89,000 53,500 67,500 Preferred stock redemption expense.................. 719 - 818 -------- -------- -------- 96,030 59,328 74,299 -------- -------- -------- Balance December 31..................................... $181,049 $193,895 $194,903 -------- -------- -------- -------- -------- --------
The accompanying notes are an integral part of these financial statements. -26- LOUISVILLE GAS AND ELECTRIC COMPANY BALANCE SHEETS (Thousands of $) ASSETS
December 31 -------------------------------- 1995 1994 ---- ---- Utility Plant, at original cost Electric.................................................. $2,123,699 $2,084,334 Gas....................................................... 299,070 280,877 Common.................................................... 128,902 137,662 ---------- ---------- 2,551,671 2,502,873 Less: Reserve for depreciation........................... 934,942 881,861 ---------- ---------- 1,616,729 1,621,012 Construction work in progress............................. 47,189 35,022 ---------- ---------- 1,663,918 1,656,034 ---------- ---------- Other Property and Investments - less reserve (Note 6)...... 760 50,681 ---------- ---------- Current Assets Cash and temporary cash investments....................... 58,131 39,138 Marketable securities (Note 6)............................ 20,449 - Accounts receivable-less reserve of $1,360 in 1995 and $1,203 in 1994......................... 105,589 86,058 Materials and supplies-at average cost Fuel (predominantly coal).............................. 14,996 13,869 Gas stored underground................................. 31,714 31,354 Other.................................................. 34,384 37,299 Prepayments............................................... 2,108 253 ---------- ---------- 267,371 207,971 ---------- ---------- Deferred Debits and Other Assets Unamortized debt expense.................................. 7,710 7,776 Regulatory assets (Note 2)................................ 29,926 31,726 Other..................................................... 9,805 12,402 ---------- ---------- 47,441 51,904 ---------- ---------- $1,979,490 $1,966,590 ---------- ---------- ---------- ---------- CAPITAL AND LIABILITIES Capitalization (see Statements of Capitalization) Common equity............................................. $605,157 $616,478 Cumulative preferred stock................................ 95,328 116,716 Long-term debt............................................ 646,845 662,862 ---------- ---------- 1,347,330 1,396,056 ---------- ---------- Current Liabilities Long-term debt due within one year........................ 16,000 - Accounts payable.......................................... 93,706 70,770 Trimble County Settlement (Note 14)....................... 28,300 - Dividends declared........................................ 19,672 19,567 Accrued taxes............................................. 7,814 8,247 Accrued interest.......................................... 11,064 13,394 Other..................................................... 12,071 10,277 ---------- ---------- 188,627 122,255 ---------- ---------- Deferred Credits and Other Liabilities Accumulated deferred income taxes (Notes 1 and 8)......... 204,816 193,236 Investment tax credit, in process of amortization......... 84,037 88,779 Accumulated provision for pensions and related benefits... 47,099 49,104 Customers' advances for construction...................... 9,251 8,621 Regulatory liability (Note 2)............................. 88,242 91,492 Other..................................................... 10,088 17,047 ---------- ---------- 443,533 448,279 ---------- ---------- Commitments and Contingencies (Note 13) $1,979,490 $1,966,590 ---------- ---------- ---------- ----------
The accompanying notes are an integral part of these financial statements. -27- LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Thousands of $)
Years Ended December 31 ---------------------------------------- 1995 1994 1993 ---- ---- ---- Cash Flows from Operating Activities Net Income........................................................ $ 83,184 $ 58,320 $ 90,535 Items not requiring cash currently: Depreciation and amortization................................... 85,759 82,519 79,887 Deferred income taxes-net....................................... 7,049 (2,274) 4,938 Investment tax credit-net....................................... (4,742) (4,619) (7,821) Cumulative effect of change in accounting principle............. - 3,369 - Non-recurring charges........................................... - 38,613 - Gain on sale of capital asset................................... - - (3,869) Other........................................................... 3,958 6,603 5,877 (Increase) decrease in certain net current assets: Accounts receivable............................................. (19,531) 18,339 (11,678) Materials and supplies.......................................... 1,428 3,280 10,671 Trimble County Settlement....................................... 28,300 - - Accounts payable................................................ 22,936 (22,781) 21,099 Accrued taxes................................................... (433) (1,247) 2,343 Accrued interest................................................ (2,330) 530 757 Prepayments and other........................................... (61) (743) (260) Other............................................................. (6,917) 972 (15,587) --------- --------- --------- Net cash provided from operating activities..................... 198,600 180,881 176,892 --------- --------- --------- Cash Flows from Investing Activities Purchases of securities........................................... (119,151) (87,896) (38,398) Proceeds from sales of securities................................. 151,422 56,085 27,301 Construction expenditures......................................... (93,423) (95,398) (98,787) Sale of capital asset............................................. - - 91,076 --------- --------- --------- Net cash used for investing activities.......................... (61,152) (127,209) (18,808) --------- --------- --------- Cash Flows from Financing Activities Issuance of preferred stock....................................... - - 24,716 Issuance of first mortgage bonds and pollution control bonds...... 39,914 - 198,918 Redemption of preferred stock..................................... (22,108) - (25,558) Retirement of first mortgage bonds and pollution control bonds.... (41,055) - (231,876) Repayment of short-term borrowings................................ - - (8,000) Payment of dividends.............................................. (95,206) (58,639) (73,125) --------- --------- --------- Net cash used for financing activities............................ (118,455) (58,639) (114,925) --------- --------- --------- Net Increase (Decrease) in Cash and Temporary Cash Investments...... 18,993 (4,967) 43,159 Cash and Temporary Cash Investments at Beginning of Year............ 39,138 44,105 946 --------- --------- --------- Cash and Temporary Cash Investments at End of Year.................. $ 58,131 $ 39,138 $ 44,105 --------- --------- --------- --------- --------- --------- Supplemental Disclosures of Cash Flow Information Cash paid during the year for: Income taxes...................................................... $ 40,049 $ 42,803 $ 54,686 Interest on borrowed money........................................ 42,589 40,827 45,360
The accompanying notes are an integral part of these financial statements. -28- LOUISVILLE GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Thousands of $)
December 31 ----------------------------- 1995 1994 ---- ---- 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 $153 in 1995 and $1,434 in 1994 (Note 6)................. (226) (1,751) Retained earnings................................................... 181,049 193,895 ---------- ---------- 605,157 616,478 ---------- ---------- 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 (Note 10)......... - - - 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............................................. (1,179) (1,244) ---------- ---------- 95,328 116,716 ---------- ---------- Long-Term Debt (Note 11) 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 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 X due April 15, 2023, 5.90%..................................... 40,000 - ---------- ---------- Total bonds outstanding........................................... 662,800 662,800 Less long-term debt due within one year........................... 16,000 - ---------- ---------- Long-term first mortgage bonds.................................... 646,800 662,800 Unamortized premium on bonds........................................ 45 62 ---------- ---------- 646,845 662,862 ---------- ---------- Total Capitalization.................................................. $1,347,330 $1,396,056 ---------- ---------- ---------- ----------
The accompanying notes are an integral part of these financial statements. -29- LOUISVILLE GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Louisville Gas and Electric Company (the Company) is the primary subsidiary of LG&E Energy Corp. The Company is a regulated public utility that is engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas in Louisville and adjacent areas in Kentucky. LG&E Energy Corp. is an exempt energy services holding company with wholly-owned subsidiaries consisting of the Company, LG&E Energy Systems Inc., and LG&E Gas Systems Inc. All of the Company's Common Stock is held by LG&E Energy Corp. Certain reclassification entries have been made to the 1994 financial statements to conform with the 1995 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 1995 were 3.3% (3.2% electric, 3.3% gas, and 6% common); for 1994, 3.3% (3.2% electric, 3.3% gas, and 5% common); and for 1993, 3.3% (3.2% electric, 3.2% gas, and 5% common) of average depreciable plant. CASH AND TEMPORARY CASH INVESTMENTS. The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value. FINANCIAL INSTRUMENTS. The Company uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in interest rates it pays on variable-rate debt, and it uses exchange-traded U.S. Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies. Gains and losses on interest-rate swaps are reflected in interest charges monthly. Gains and losses on U.S. Treasury note and bond futures used to hedge investments in preferred stocks are initially deferred and classified as unrealized loss on marketable securities in common equity and then charged or credited to other income and deductions when the securities are sold. See Note 4, Financial Instruments. -30- DEFERRED INCOME TAXES. Deferred income taxes have been provided for all book-tax temporary differences. The Company adopted Statement of Financial Accounting Standards No. 109, ACCOUNTING FOR INCOME TAXES (SFAS No. 109) 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. MANAGEMENT'S USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 13, Commitments and Contingencies, for further discussion. NEW ACCOUNTING PRONOUNCEMENT. LONG-LIVED ASSETS - In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF (SFAS No. 121), effective for fiscal years beginning after December 15, 1995. The Company plans to adopt the provisions of SFAS No. 121 in the first quarter of 1996. The new standard requires that long-lived assets and certain identified intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing such impairment reviews, companies will be required to estimate the sum of future cash flows from an asset and compare such amount to the asset's carrying amount. Any excess of carrying amount over expected cash flows will result in a possible write-down of an asset to its fair value. Based on current operating -31- conditions, legal requirements and regulatory environment, the Company does not expect adoption of SFAS No. 121 to have a material adverse impact on its financial position or results of operations. NOTE 2 - RATES AND REGULATORY MATTERS The Company conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by the Federal Energy Regulatory Commission (FERC) and the Kentucky Commission. The Company is subject to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71). Under SFAS No. 71, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in the balance sheets as of December 31 (in thousands of $):
1995 1994 ---- ---- Unamortized loss on bonds................... $ 16,443 $ 15,704 Unamortized extraordinary retirements....... 6,935 9,752 Manufactured gas sites...................... 3,220 3,149 Other....................................... 3,328 3,121 -------- -------- Total regulatory assets..................... 29,926 31,726 Deferred income taxes - net................. (88,242) (91,492) -------- -------- Regulatory assets and (liabilities) - net... $(58,316) $(59,766) -------- -------- -------- --------
Substantially all of the Company's regulatory assets are being recovered through rates charged to customers. The Company expects to seek regulatory approval to recover any remaining regulatory assets in its next general rate case. ENVIRONMENTAL COST RECOVERY. The Company filed an application with the Kentucky Commission in October 1994, in which it requested approval of an environmental cost recovery surcharge to recover certain costs incurred to comply with federal, state, and local environmental requirements. On April 6, 1995, the Commission approved the surcharge with modifications. The surcharge became effective on May 1, 1995. The Company recovered $3.2 million in 1995 and expects to recover an additional $5.7 million in 1996 through the surcharge. An appeal of the Commission's April 6 order by various intervenors in the proceeding (including the Kentucky Attorney General) is currently pending in the Franklin Circuit Court of Kentucky. The intervenors are contesting the validity of the order on several grounds, including the constitutionality of the Kentucky statute that authorizes the surcharge. The Company is vigorously contesting the legal challenges to the surcharge, but cannot predict the outcome of the appeal. The amount of refunds that may be ordered, if any, are not expected to have a material adverse effect on the Company's financial position or results of operations. See Management's Discussion and Analysis, Rates and Regulation, under Item 7 for a further discussion. -32- NOTE 3 - NON-RECURRING CHARGES As part of a study of LG&E Energy Corp.'s business strategy and realignment during 1994, the Company re-evaluated its regulatory strategy which previously had been to seek full recovery of certain costs deferred in accordance with prior precedents established by the Commission. As a result of this re-evaluation, the Company wrote off certain expenses that had previously been deferred amounting to approximately $38.6 million before taxes. While the Company continues to believe that it could have reasonably expected to recover these costs in future rate proceedings before the Commission, the Company decided to deduct these expenses currently and not seek recovery for such expenses in future rates due to increasing competitive pressures and the existing and anticipated future economic conditions. The items written off include costs incurred in connection with early retirements and workforce reductions that occurred in 1992 and 1993, which consist primarily of separation payments, enhanced early retirement benefits, and health care benefits; costs associated with property damage claims pertaining to particulate emissions from its Mill Creek electric generating plant which primarily consist of spotting on automobile finish and aluminum siding; and certain costs previously deferred resulting from adoption in January 1993 of Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS. In the first quarter of 1994, the Board of Directors of the Company approved the formation of a tax-exempt charitable foundation (Foundation) that makes charitable contributions to qualified persons and entities. In 1994, the Company recorded a pre-tax charge against income and made an irrevocable payment of $15 million to fund the Foundation. 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 - FINANCIAL INSTRUMENTS INSTRUMENTS USED IN HEDGING ACTIVITIES. The Company uses exchange-traded futures and over-the-counter (OTC) swap agreements to hedge its exposure to changes in the valuation of investments in marketable securities and changes in interest rates on variable rate debt, respectively. Futures reduce exposure to fluctuations in pricing of marketable securities as of a future delivery date. Swaps allow the Company to change certain index-based interest payment commitments to fixed amounts based on a stated rate. -33- The following summarizes the Company's use of financial instruments for hedging purposes at December 31, 1995:
NOTIONAL AMOUNT CATEGORY /MATURITY PURPOSE ----------------------------- ------------------------------- ------------------------------ Exchange-traded U.S. Treasury $4.3 million, matures March Reduce exposure to changes in notes and bond futures 1996 market value of investments in preferred stock. OTC interest rate swaps $15 million matures September Convert $30 million of Series S 1997; $15 million matures variable rate Pollution Control September 1999 Bonds to average composite rates of 4.55%. Average variable rate received based on JJ Kenny index, 3.87%, 2.84%, and 2.38% in 1995, 1994, and 1993, respectively.
Initial margin requirements and daily margin calls for exchange-traded futures are met in cash and all transactions are settled in cash or through delivery of the underlying security. FAIR VALUES OF FINANCIAL INSTRUMENTS. The carrying amounts of cash, accounts receivable, 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 exchange-traded financial instruments reflects market prices reported by the exchanges. Fair values of swaps are based on price quotes obtained from dealers. Fair value estimates are made at a certain point in time and changes in assumptions, economic conditions, risk characteristics of various instruments and other factors could cause significant changes in these estimates. The fair value information contained herein does not include an assessment of assets and liabilities that are not financial instruments, such as property and equipment or other assets and liabilities. Accordingly, these fair value disclosures are not intended to present a valuation of the Company taken as a whole. -34- The cost and estimated fair values of the Company's financial instruments as of December 31, 1995 and 1994 follow (in thousands of $):
1995 1994 ------------------------ ------------------------- Fair Fair Cost Value Cost Value -------- --------- --------- -------- Marketable securities............................. $ 20,828 $ 20,449 $ - $ - Long-term investments: Practicable to estimate fair value.............. - - 53,323 50,138 Not practicable................................. 740 740 515 515 Preferred stock subject to mandatory redemption... 25,000 25,000 25,000 22,125 Long-term debt.................................... 662,800 688,977 662,800 648,697 U.S. Treasury note and bond futures............... - (105) (a) - (383) OTC interest rate swaps........................... - (522) - 965
(a) Gains and losses realized on the future sale or purchase of marketable securities will generally offset any net unrealized gains and losses. See Note 5, Concentrations of Credit and Other Risk, for a discussion of credit risk as it pertains to certain of the above financial instruments. NOTE 5 - CONCENTRATIONS OF CREDIT AND OTHER RISK Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties (See Note 4, Financial Instruments, for further discussion) failed completely to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions. The Company does not have a significant loss exposure to any individual customer or counterparty. The Company's customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 272,000 customers and electricity to approximately 346,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 1995, 75% of total revenue was derived from electric operations and 25% from gas operations. The Company's operation and maintenance employees are members of the International Brotherhood of Electrical Workers (IBEW) Local 2100 which represents approximately one-half of the Company's workforce. The Company's collective bargaining agreement with IBEW employees expires in November 1998. NOTE 6 - MARKETABLE SECURITIES The Company adopted the provisions of Statement of Financial Accounting Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES 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 balance sheets. The available-for-sale category of investments results in the classification of unrealized gains and losses on investments in common equity, net of income taxes, until such gains and losses are realized, at which time they are recognized in earnings. Proceeds from sales of available-for-sale securities in 1995 were $151,422,000, which resulted in realized gains of -35- $1,621,000 and losses of $3,440,000, calculated using the specific identification method. Proceeds from sales of available-for-sale securities in 1994 were $56,085,000, which resulted in realized gains of $1,557,000 and losses of $1,538,000. The differences between amortized and unamortized cost basis of the Company's investments in marketable securities as of December 31, 1995 and 1994, were 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, 1995 and 1994, follow (in thousands of $):
1995 1994 ------------------------------------- --------------------------------------- Fixed Fixed Equity Income Total Equity Income Total -------- -------- ------- -------- -------- -------- Cost....................... $7,399 $13,429 $20,828 $23,622 $29,701 $53,323 Unrealized gains........... 58 1 59 41 - 41 Unrealized losses.......... (198) (240) (438) (2,399) (827) (3,226) ------ ------- ------- ------- ------- ------- Fair values................ $7,259 $13,190 $20,449 $21,264 $28,874 $50,138 ------ ------- ------- ------- ------- ------- ------ ------- ------- ------- ------- ------- - ------------------------------------------------------------------------------------------------------------------- Fair Values: No maturity.............. $6,620 $ - $ 6,620 $20,415 $ - $20,415 Maturities: Less than one year..... 639 2,710 3,349 849 2,519 3,368 One to five years...... - 8,808 8,808 - 16,968 16,968 Five to ten years...... - 831 831 - 1,958 1,958 Over ten years......... - 164 164 - 3,381 3,381 No single date......... - 677 677 - 4,048 4,048 ------ ------- ------- ------- ------- ------- Total Fair Values.......... $7,259 $13,190 $20,449 $21,264 $28,874 $50,138 ------ ------- ------- ------- ------- ------- ------ ------- ------- ------- ------- -------
The Company's available-for-sale securities were classified as Marketable Securities at December 31, 1995. In 1994, available-for-sale securities were classified as Other Property and Investments in the accompanying balance sheet. NOTE 7 - 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, age at retirement and compensation. The Company's policy is to fund annual actuarial costs, up to the maximum amount deductible for income tax purposes, as determined under the frozen entry age actuarial cost method. The assets of the plans consist primarily of common stocks, corporate bonds and United States government securities. The Company also has a supplemental executive retirement plan that covers officers of the Company. The plan provides retirement benefits based on average earnings during the final three years prior to retirement, reduced by social security benefits, any pension benefits received from plans of prior employers, and by amounts received under the pension plans referred to in the preceding paragraph. -36- Pension costs were $4,977,000 for 1995, $4,423,000 for 1994, and $2,669,000 for 1993, of which approximately $761,000, $693,000, and $425,000, respectively, were charged to construction. The components of periodic pension expense are shown below (in thousands of $):
1995 1994 1993 ---- ---- ---- Service cost-benefits earned during the period.. $ 4,361 $ 4,813 $ 4,516 Interest cost on projected benefit obligation... 14,328 13,057 12,117 Actual return on plan assets.................... (45,608) (489) (13,602) Amortization of transition asset................ (1,112) (1,112) (1,112) Net amortization and deferral................... 33,008 (11,846) 750 -------- -------- -------- Net pension cost................................ $ 4,977 $ 4,423 $ 2,669 -------- -------- -------- -------- -------- --------
The funded status of the pension plans at December 31 is shown below (in thousands of $):
1995 1994 ---- ---- Actuarial present value of accumulated plan benefits: Vested............................................... $166,525 $132,260 Non-Vested........................................... 8,577 14,023 -------- -------- Accumulated benefit obligation....................... 175,102 146,283 Effect of projected future compensation.............. 31,764 18,473 -------- -------- Projected benefit obligation......................... 206,866 164,756 Plan assets at fair value............................ 207,470 159,638 -------- -------- Plan assets in excess of (less than) projected benefit obligation................................. 604 (5,118) Unrecognized net transition asset.................... (11,412) (12,524) Unrecognized prior service cost...................... 28,938 24,257 Unrecognized net gain................................ (43,652) (36,266) -------- -------- Accrued pension liability.............................. $(25,522) $(29,651) -------- -------- -------- --------
The assumptions used in determining the actuarial valuations are as follows:
1995 1994 ---- ---- Assumed discount rate to determine projected benefit obligation........... 7.5% 8.5% Assumed long-term rate of return on plan assets......................... 8.5% 8.5% Assumed annual rate of increase in future compensation levels............. 3.5% - 4% 4.5% - 5%
POST-RETIREMENT BENEFITS. The Company provides certain health care and life insurance benefits for eligible retired employees. Post-retirement health care benefits are subject to a maximum amount payable by the Company. The Company adopted Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS (SFAS No. 106) January 1, 1993. SFAS No. 106 requires the accrual of the expected cost of retiree benefits other than pensions during the employee's years of service with the Company. The Company is amortizing the discounted present value of the post-retirement benefit obligation at the date of adoption over 20 years. Prior to January 1, -37- 1993, the cost of retiree health care and life insurance benefits was generally recognized when paid. The components of the net periodic post-retirement benefit cost as calculated under SFAS No. 106 are as follows (in thousands of $):
1995 1994 1993 ---- ---- ---- Service cost ........................... $ 595 $ 621 $ 701 Interest cost........................... 2,706 2,386 2,614 Amortization of transition obligation... 1,337 1,337 1,395 ------ ------ ------ Post-retirement benefit cost............ $4,638 $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 $):
1995 1994 ---- ---- Retirees............................................ $(19,965) $(18,487) Fully eligible active employees..................... (2,768) (1,927) Other active employees.............................. (15,082) (9,789) -------- -------- Accumulated post-retirement benefit obligation...... (37,815) (30,203) Unrecognized net loss (gain)........................ 3,480 (3,275) Unrecognized transition obligation.................. 22,727 24,064 -------- -------- Accrued post-retirement benefit liability........... $(11,608) $ (9,414) -------- -------- -------- --------
The accumulated post-retirement benefit obligation was determined using an assumed discount rate of 7.5% for 1995 and 8.5% for 1994. Assumed compensation increases for projected life insurance benefits for affected groups was 4% for 1995 and 5% for 1994. An assumed health care cost trend rate of 10% was assumed for 1995, gradually decreasing to 5% 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 $1.5 million and the annual service and interest cost by approximately $200,000. No funding has been established by the Company for post-retirement benefits. POST-EMPLOYMENT BENEFITS. The Company adopted Statement of Financial Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS (SFAS No. 112) January 1, 1994. 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. See Note 3, Non-Recurring Charges. -38- 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 $1,750,000 for 1995, $1,701,000 for 1994, and $1,795,000 for 1993. NOTE 8 - FEDERAL AND STATE INCOME TAXES Components of income tax expense are shown in the table below (in thousands of $):
1995 1994 1993 ---- ---- ---- Included in Operating: Current - Federal........................ $36,379 $35,552 $31,082 - State.......................... 9,138 9,003 8,920 Deferred - Federal-net.................... 4,021 (969) 13,185 - State-net...................... 2,728 955 3,933 Amortization of investment tax credit..... (4,742) (4,619) (4,786) ------- ------- ------- Total................................. $47,524 $39,922 $52,334 ------- ------- ------- Included in Other Income and (Deductions): Current - Federal........................ $ (555) $(4,626) $11,009 - State.......................... (343) (1,277) 4,034 Deferred - Federal-net.................... 240 19 (8,473) - State-net...................... 60 1 (3,707) Amortization of investment tax credit..... - - (3,035) ------- ------- ------- Total................................. $ (598) $(5,883) $ (172) ------- ------- ------- 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.................... $46,926 $31,759 $52,162 ------- ------- ------- ------- ------- -------
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 $):
1995 1994 1993 ---- ---- ---- Depreciation and amortization................. $15,140 $12,609 $ (255) Alternative minimum tax....................... - - 5,387 Pension overfunding........................... 2,078 (4,357) (823) Accrued liabilities not currently deductible.. (9,076) (5,343) 1,210 Change in accounting principle................ - (2,280) - Other........................................ (1,093) (2,903) (581) ------- ------- ------ Total....................................... $ 7,049 $(2,274) $4,938 ------- ------- ------ ------- ------- ------
-39- The net provisions for deferred income taxes increased in 1995 largely due to current year funding of one of the Company's defined-benefit pension plans. Fluctuations in deferred income taxes attributable to liabilities accrued for financial reporting, which are not currently deductible on the Company's tax return, occurred in 1995 and 1994 due to the timing of when such liabilities are paid. Deferred income taxes attributable to depreciation and amortization in 1993 reflect the reversal of prior years' accumulated deferred income taxes as a result of the sale of a portion of Trimble County Unit 1. See Note 15, Jointly Owned Electric Utility Plant, for a further discussion of the sale. Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
1995 1994 ---- ---- Deferred Tax Liabilities: Depreciation and other plant related items... $297,929 $281,696 Other liabilities............................ 7,714 7,305 -------- -------- 305,643 289,001 -------- -------- Deferred Tax Assets: Investment tax credit........................ 33,919 35,833 Income taxes due to customers................ 32,363 33,456 Pension overfunding.......................... 9,075 11,145 Other assets................................. 25,470 15,331 -------- -------- 100,827 95,765 -------- -------- Net deferred income tax liability.......... $204,816 $193,236 -------- -------- -------- --------
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:
1995 1994 1993 ---- ---- ---- Statutory Federal income tax rate............. 35.0% 35.0% 35.0% State income taxes net of Federal benefit..... 5.8 5.9 6.0 Amortization of investment tax credit......... (3.6) (5.1) (5.5) Other differences-net......................... (1.1) (.5) 1.1 ---- ---- ---- Effective Income Tax Rate..................... 36.1% 35.3% 36.6% ---- ---- ---- ---- ---- ----
NOTE 9 - OTHER INCOME AND DEDUCTIONS Other income and deductions consisted of the following at December 31 (in thousands of $):
1995 1994 1993 ---- ---- ---- Interest and dividend income....................... $ 5,732 $ 4,568 $ 3,112 Gains (losses) on fixed asset disposal............. 1,090 1,427 (3,523) Gain on sale of 12.88% portion of Trimble County... - - 3,869 Donations.......................................... (144) (1,015) (909) Income taxes and other............................. (2,902) (2,529) (636) ------- ------- ------- Total other income and deductions.................. $ 3,776 $ 2,451 $ 1,913 ------- ------- ------- ------- ------- -------
-40- NOTE 10 - PREFERRED STOCK In December 1995, the Company redeemed the 858,128 outstanding shares of its 7.45% Cumulative Preferred Stock with a par value of $25 per share at a redemption price of $25.75 per share. NOTE 11 - FIRST MORTGAGE BONDS Annual requirements for the sinking funds of the Company's First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with the Pollution Control Bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166 2/3% of principal amounts of bonds otherwise required to be so redeemed) have been applied in lieu of cash. It is the intent of the Company to apply property additions to meet 1996 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 April 1995, the Company issued $40 million of Jefferson County, Kentucky, Pollution Control Revenue Bonds, 5.90% Series, due April 15, 2023. The proceeds of the bonds were used to redeem the outstanding 9.25% Series of Pollution Control Bonds due July 1, 2015. The Company has outstanding interest rate swap agreements totaling $30 million related to its Pollution Control Revenue Bonds, Variable Rate Series, due September 1, 2017. See Note 4, Financial Instruments. The Company's First Mortgage Bonds, 5.625% Series of $16 million is scheduled to mature June 1, 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, 1995. The Company has no cash sinking fund requirements. NOTE 12 - NOTES PAYABLE The Company had no notes payable at December 31, 1995, and 1994. -41- At December 31, 1995, the Company had unused lines of credit of $160 million, for which it pays commitment fees. The credit lines are scheduled to expire during the year 2000. Management expects to renegotiate these lines when they expire. NOTE 13 - COMMITMENTS AND CONTINGENCIES CONSTRUCTION PROGRAM. The Company had commitments in connection with its construction program aggregating approximately $11 million at December 31, 1995. Construction expenditures for the years 1996 and 1997 are estimated to total approximately $220 million. FERC ORDER NO. 636. Prior to the implementation of Order No. 636, the Company had purchased natural gas and pipeline transportation services from Texas Gas Transmission Corporation (Texas Gas). The Company now purchases only transportation services from Texas Gas and purchases natural gas from many other sources under contracts for varying periods of time. See Management's Discussion and Analysis, Future Outlook, under Item 7. 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 1995, the Company paid Texas Gas and began recovering from its customers approximately $4.8 million in transition costs. It is estimated that about $1.4 million in additional transition costs will be incurred by the Company during 1996 and about $1.3 million in 1997, and these costs are also expected to be recovered from customers. These transition costs are billed by Texas Gas pursuant to orders issued by FERC in transition cost regulatory proceedings in which the Company is a party. Pursuant to these FERC orders, no additional transition costs are expected to be billed after 1997. 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 1995, 1994, and 1993 was $2,020,000, $2,192,000, and $2,436,000, respectively. The future minimum annual lease payments under the lease agreement for years subsequent to December 31, 1995, are as follows (in thousands of $): 1996............................. $ 2,850 1997............................. 2,850 1998............................. 2,850 1999............................. 2,850 2000............................. 3,178 Thereafter....................... 15,782 ------- Total......................... $30,360 ------- -------
ENVIRONMENTAL. The Clean Air Act Amendments of 1990 (the Act) impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. 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. All of the -42- 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 $22 million to date and, based on engineering estimates from contractors, anticipates incurring additional capital expenditures of approximately $8 million in 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. In May 1994, the Company completed extensive modification at its Mill Creek plant aimed at controlling certain particulate emissions which have allegedly damaged metal surfaces on adjacent properties. The Air Pollution Control District of Jefferson County (APCD) and the Company are currently conducting a field sampling program to demonstrate the effectiveness of the plant modifications. In an effort to resolve property damage claims of adjacent residents, the Company commenced extensive negotiations and property damage settlements with residents who are not parties to any pending litigation. Through December 1995, the Company has settled property damage claims filed by residents at an aggregate cost of approximately $14.7 million. In management's opinion, settlement of the limited number of these remaining non-litigated claims should not have a material adverse impact on the financial position or results of operations of the Company. 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 who have allegedly suffered personal injury or property damage as a result of emissions from the plant. The plaintiffs sought compensation for personal injury and property damage, 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. In August 1995, the court granted the plaintiffs' motion for leave to file an amended complaint to bring a total of 537 individual plaintiffs into the pending litigation. The plaintiffs subsequently filed a motion to certify a class consisting of all persons within 3.5 miles of the plant who have allegedly suffered property damage. The court has not yet ruled on that motion. In January 1996, the plaintiffs waived all claims for compensation for personal injuries, fear of cancer, emotional distress, loss of income, injunctive relief, and medical monitoring. The Company stipulated nuisance as to plaintiffs located within 2.5 miles of the plant, but reserved the right to assert lack of causation and all affirmative defenses including statute of limitations. The plaintiffs also waived claims for punitive damages with respect to all plaintiffs located within 2.5 miles. The plaintiffs are currently pursuing claims solely for property damage and annoyance allegedly due to emissions from the plant. The Company intends to vigorously defend itself in the pending litigation. In response to a notification from the APCD that the Company's Cane Run plant may be the source of a potential exceedance of the National Ambient Air Quality Standards for sulfur dioxide, the Company submitted a draft action plan and modeling schedule to the APCD and the United States Environmental Protection Agency (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. -43- In March 1994, the APCD adopted a regulation requiring a 15% reduction from 1990 volatile organic compound (VOC) emissions from industrial sources in an effort to ensure compliance with the National Ambient Air Quality Standards for ozone. 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 for an exclusion from the VOC reduction requirements. As an alternative, the APCD is considering additional nitrogen oxide reduction requirements for the Company. The Company cannot determine the precise impact of this matter. The Company owns or formerly owned three primary sites where manufactured gas plant operations were conducted. Remedial investigations performed at the three sites have identified coal tar and other contaminants typical of manufactured gas plant operations. The Company is currently awaiting regulatory determinations from the Kentucky Natural Resources and Environmental Protection Cabinet on the level of remediation required for each site. Until such regulatory determinations are made, the Company is unable to precisely determine cleanup costs for these sites. However, based on the results of studies at the three sites, management currently estimates that total cleanup costs 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. The Company, along with a number of other companies, has been identified as a potentially responsible party (PRP) allegedly liable for cleanup under the Comprehensive Environmental Response Compensation and Liability Act as amended at four off-site waste treatment or disposal sites. Under the law, each PRP potentially could be held jointly and severally liable for the cost of cleanup, but would have the right to seek contribution from other PRPs. The sites targeted for cleanup in which the Company has been identified as a PRP include: the Smith's Farm site located in Bullitt County, Kentucky, the Sonora and Carlie Middleton Burn sites located in Hardin County, Kentucky, and the M.T. Richards site located in Crossville, Illinois. With respect to the Smith's Farm site, USEPA has identified the Company as a de minimis PRP and is currently pursuing other parties for the vast majority of the $60 million in cleanup costs as estimated by USEPA. The Company is participating in settlement discussions in an effort to resolve any alleged liability which it may have. With respect to the Sonora Site and Carlie Middleton Burn Site, the Company is involved in litigation with USEPA and approximately 10 companies in an effort to resolve liability for approximately $1.8 million in cleanup costs incurred by USEPA. With respect to the M.T. Richards site, the Company has been identified as a de minimis party and has reached a tentative settlement for $7,500, subject to approval by the government and entry by the court. While it is not possible at this time to predict the exact outcome or precise impact of these matters, management believes that these matters should not have a material adverse impact on the financial position or results of operations of the Company. NOTE 14 - TRIMBLE COUNTY GENERATING PLANT Trimble County Unit 1 (Trimble County), a 495-megawatt coal-fired electric generating unit placed into service in December 1990, has been the subject of numerous legal and regulatory proceedings to determine the appropriate ratemaking treatment to implement the Kentucky -44- Public Service Commission's 1988 decision that the Company should not be allowed to recover 25% of the cost of the Unit from ratepayers. On July 19, 1995, the Commission issued an order in which it ruled that the Company refund $33.8 million to its electric customers, including interest. The Commission stated in its July 19 order that the principal amount to be refunded represented 25% of the revenues collected by the Company, during the period May 1988 through December 1990, on Trimble County construction work in progress (CWIP) included in the Company's rate base in the 1988 rate case. The order also required the Company to file a plan for implementing the refund. On December 1, 1995, the Company and the other parties to the proceedings filed with the Commission a unanimous settlement agreement that was approved by the Commission on December 8, 1995. Under the agreement, which resolves all outstanding issues, the Company has agreed to refund approximately $22 million to current electric customers, the majority of which will be paid by credits to customers' bills over five years. In addition, the Company has agreed to pay $900,000 per year for five years to the Metro Human Needs Alliance, Inc., a not-for-profit Louisville-based corporation, for the sole purpose of funding low-income energy assistance programs in the service territory. The Company also agreed to revise the residential decoupling methodology approved by the Commission in 1994 in a manner that would reduce revenues collected from residential customers during 1996 and 1997 by a total of approximately $1.8 million. Finally, the parties agreed that all appeals currently pending in state courts regarding the Commission's orders in the Company's most recent general rate case would be dismissed. Reference is made to Note 15, Jointly Owned Electric Utility Plant, for a discussion of the sale of 25% of Trimble County. NOTE 15 - JOINTLY OWNED ELECTRIC UTILITY PLANT The Company owns a 75% undivided interest in Trimble County Unit 1. Accounting for the 75% portion of the Unit, which the Commission has allowed to be reflected in customer rates, is similar to the Company's accounting for other wholly-owned utility plants. Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA) purchased a 12.12% undivided interest in the Unit on February 28, 1991, and Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided interest on February 1, 1993. Each is responsible for their proportionate ownership share of operation and maintenance expenses and incremental assets, and for fuel used. The following data represent shares of the jointly owned property:
Trimble County ------------------------------------- LG&E IMPA IMEA Total ---- ---- ---- ----- Ownership interest....... 75% 12.88% 12.12% 100% Mw capacity.............. 371.25 63.75 60 495
-45- NOTE 16 - SEGMENTS OF BUSINESS The Company is a regulated public utility engaged in the generation, transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas.
1995 1994 1993 ---- ---- ---- (Thousands of $) Operating Information Operating Revenues Electric........................... $ 542,337(a) $ 558,946 $ 570,210 Gas................................ 181,126 200,129 204,915 ---------- ---------- ---------- Total............................ $ 723,463 $ 759,075 $ 775,125 ---------- ---------- ---------- ---------- ---------- ---------- Pre-tax Operating Income Electric........................... $ 152,199 $ 139,594 $ 171,016 Gas................................ 16,651 11,368 17,436 ---------- ---------- ---------- Total............................ $ 168,850 $ 150,962 $ 188,452 ---------- ---------- ---------- ---------- ---------- ---------- Other Information Depreciation and Amortization Electric........................... $ 74,437 $ 71,882 $ 69,753 Gas................................ 11,322 10,637 9,902 Non-Jurisdictional................. - - 232 ---------- ---------- ---------- Total............................ $ 85,759 $ 82,519 $ 79,887 ---------- ---------- ---------- ---------- ---------- ---------- Construction Expenditures Electric........................... $ 66,661 $ 71,592 $ 74,165 Gas................................ 26,762 23,806 24,622 ---------- ---------- ---------- Total............................ $ 93,423 $ 95,398 $ 98,787 ---------- ---------- ---------- ---------- ---------- ---------- Investment Information-December 31 Identifiable Assets Electric........................... $1,501,568 $1,514,287 $1,537,387 Gas................................ 268,840 252,946 241,930 ---------- ---------- ---------- Total............................ 1,770,408 1,767,233 1,779,317 Other Assets (b).................... 209,082 199,357 195,267 ---------- ---------- ---------- Total Assets..................... $1,979,490 $1,966,590 $1,974,584 ---------- ---------- ---------- ---------- ---------- ----------
(a) Net of Refund - Trimble County Settlement of $28.3 million. (b) Includes cash and temporary cash investments, marketable securities, accounts receivable, unamortized debt expense, and other property and investments. -46- 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, 1995 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. -47- 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, 1995 and 1994, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. As discussed in Notes 1 and 7 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, 1996 ------------------------------------------ -48- SELECTED QUARTERLY FINANCIAL DATA (Unaudited) (Thousands of $) Selected financial data for the four quarters of 1995 and 1994 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 ----- ---- --------- -------- 1995 Operating Revenues.................. $199,517 $167,821 $196,351 $159,774(a) Net Operating Income................ 32,409 30,015 47,774 11,128 Net Income.......................... 21,839 21,085 38,346 1,914 Net Income Available for Common Stock...................... 20,222 19,458 36,780 413 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) 20,636 35,438 18,941 Net Income (Loss) Available for Common Stock...................... (18,073) 19,256 33,935 17,374
(a) Net of Refund - Trimble County Settlement of $28.3 million. ---------------------------------- ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. -49- 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 13, 1996, 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, 1995, 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, 1995 (page 26). Statements of Retained Earnings for the three years ended December 31, 1995 (page 26). Balance Sheets - December 31, 1995, and 1994 (page 27). Statements of Cash Flows for the three years ended December 31, 1995 (page 28). Statements of Capitalization - December 31, 1995, and 1994 (page 29). Notes to Financial Statements (pages 30-46). Report of Management (page 47). Report of Independent Public Accountants (page 48). Selected Quarterly Financial Data for 1995 and 1994 (page 49). 2. Financial Statement Schedule (included in Part IV): Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 1995 (page 66). 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. -50- 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 December 15, 1995. 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] -51- 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] -52- 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] -53- 4.22 Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to the Company's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein] 4.23 Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.23 to the Company's Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein] 4.24 Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein] 4.25 Copy of Supplemental Indenture dated November 15, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein] 4.26 Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein] 4.27 Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein] 4.28 Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein] 4.29 Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein] -54- 4.30 Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein] 4.31 Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein] 4.32 Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 4.33 Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 4.34 Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 4.35 Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 4.36 Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.01 Copies of Agreement between Sponsoring Companies re: Project D of Atomic Energy Commission, dated May 12, 1952, Memorandums of Understanding between Sponsoring Companies re: Project D of Atomic Energy Commission, dated September 19, 1952 and October 28, 1952, and Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission, dated October 15, 1952. [Filed as Exhibit 13(y) to Registration Statement 2-9975 and incorporated by reference herein] -55- 10.02 Copy of Modification No. 1 dated July 23, 1953, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4.03(b) to Registration Statement 2-24920 and incorporated by reference herein] 10.03 Copy of Modification No. 2 dated March 15, 1964, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02(c) to Registration Statement 2-61607 and incorporated by reference herein] 10.04 Copy of Modification No. 3 and No. 4 dated May 12, 1966 and January 7, 1967, respectively, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibits 4(a)(13) and 4(a)(14) to Registration Statement 2-26063 and incorporated by reference herein] 10.05 Copy of Modification No. 5 dated August 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 13(c) to Registration Statement 2-27316 and incorporated by reference herein] 10.06 Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02(f) to Registration Statement 2-61607 and incorporated by reference herein] 10.07 Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to Registration Statement 2-26063 and incorporated by reference herein] 10.08 Copies of Amendments to Agreements (iii) and (iv) referred to under 10.07 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02(h) to Registration Statement 2-61607 and incorporated by reference herein] -56- 10.09 Copy of Modification No. 1, dated August 20, 1958, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02(i) to Registration Statement 2-61607 and incorporated by reference herein] 10.10 Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02(j) to Registration Statement 2-61607 and incorporated by reference herein] 10.11 Copy of Modification No. 3, dated January 20, 1967, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to Registration Statement 2-26063 and incorporated by reference herein] 10.12 Copy of Modification No. 6, dated November 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4(g) to Registration Statement 2-28524 and incorporated by reference herein] 10.13 Copy of Modification No. 3, dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02(m) to Registration Statement 2-37368 and incorporated by reference herein] 10.14 Copy of Modification No. 7, dated November 5, 1975, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02(n) to Registration Statement 2-56357 and incorporated by reference herein] 10.15 Copy of Modification No. 4, dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02(o) to Registration Statement 2-56357 and incorporated by reference herein] 10.16 Copy of Modification No. 4, dated April 30, 1976, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02(p) to Registration Statement 2-61607 and incorporated by reference herein] -57- 10.17 Copy of Modification No. 8, dated June 23, 1977, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02(q) to Registration Statement 2-61607 and incorporated by reference herein] 10.18 Copy of Modification No. 9, dated July 1, 1978, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02(r) to Registration Statement 2-63149 and incorporated by reference herein] 10.19 Copy of Modification No. 10, dated August 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.20 Copy of Modification No. 11, dated September 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.21 Copy of Modification No. 5, dated September 1, 1979, to the Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.22 Copy of Modification No. 12, dated August 1, 1981, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 10.23 Copy of Modification No. 6, dated August 1, 1981, to the Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 10.24 Copy of Diversity Power Agreement dated September 9, 1987, between East Kentucky Power Cooperative and the Company covering the purchase and sale of power between the two companies from 1988 through 1995. [Filed as Exhibit 10.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein] -58- 10.25 Copy of Supplemental Executive Retirement Plan as amended through January 3, 1990, covering all officers of the Company. [Filed as Exhibit 10.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, and incorporated by reference herein] 10.26 Copy of LG&E Energy Corp. Deferred Stock Compensation Plan effective January 1, 1992, covering non-employee directors of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein] 10.27 Copy of form of change in control agreement for officers of Louisville Gas and Electric Company. [Filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.28 Copy of Supplemental Executive Retirement Plan for Roger W. Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.29 Copy of Nonqualified Savings Plan covering officers of the Company, effective January 1, 1992. [Filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.30 Copy of Modification No. 13, dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.31 Copy of Modification No. 14, dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.32 Copy of Modification No. 7, dated January 15, 1992, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] -59- 10.33 Copy of Modification No. 15, dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.34 Copy of Firm 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] 10.35 Copy of 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] Copy of 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] Copy of 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] 10.36 Copy of 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] 10.37 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] -60- 10.38 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. [Filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994, and incorporated by reference herein] 10.39 Copy of Amendment No. 1, dated January 1, 1991, to the Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. [Filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994, and incorporated by reference herein] 10.40 Copy of Amendment No. 2, dated November 27, 1991, to the Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994, and incorporated by reference herein] 10.41 Copy of Amendment No. 3, dated January 1, 1994, to the Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. [Filed as Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994, and incorporated by reference herein] 10.42 Copy of Amendment No. 4, dated January 1, 1995, to the Coal Supply Agreement, dated August 9, 1989, between Shawnee Coal Company, Roberts Brothers Coal Company, and the Company covering the purchase of coal. [Filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994, and incorporated by reference herein] 10.43 Copy of Modification No. 8, dated January 19, 1994, to the Inter-Company Power Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. 10.44 Copy of Amendment dated March 1, 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year, and 8-Year), between Texas Gas Transmission Corporation and the Company covering the transmission of natural gas. -61- 10.45 Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and the Company (expires October 31, 1998) covering the transportation of natural gas. Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and the Company (expires October 31, 2001) covering the transportation of natural gas. 10.46 Copy of Coal Supply Agreement, dated January 1, 1996, between Lafayette Coal Company, Black Beauty Coal Company and the Company covering the purchase of coal. 10.47 Copy of Coal Supply agreement, dated January 1, 1996, between Green Coal Company and the Company covering the purchase of coal. 10.48 Copy of Coal Supply Agreement, dated December 15, 1995, between W. B. Coal Company, Inc., Windsor Coal Company and the Company covering the purchase of coal. 10.49 Copy of Coal Supply Agreement dated January 1, 1996, between Peabody Coalsales Company and the Company covering the purchase of coal. 10.50 Copy of Amended and Restated Omnibus Long-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.52 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.51 Copy of Short-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.53 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.52 Copy of form of first amendment to change in control agreement for officers of the Company and key employees. [Filed as Exhibit 10.54 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.53 Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] -62- 10.54 Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.55 Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.56 Copy of Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1992. [Filed as Exhibit 10.58 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.57 Copy of Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1993. [Filed as Exhibit 10.59 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.58 Copy of Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1995. [Filed as Exhibit 10.60 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.59 Copy of Amendment to the Supplemental Executive Retirement Plan, effective May 1, 1995. [Filed as Exhibit 10.61 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 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] -63- 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] Amended and Restated Omnibus Long-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.52 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Short-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.53 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Form of first amendment to change in control agreement for officers of the Company and key employees. [Filed as Exhibit 10.54 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] -64- Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1992. [Filed as Exhibit 10.58 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1993. [Filed as Exhibit 10.59 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Amendment to the Supplemental Executive Retirement Plan, effective January 1, 1995. [Filed as Exhibit 10.60 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] Amendment to the Supplemental Executive Retirement Plan, effective May 1, 1995. [Filed as Exhibit 10.61 to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] (c) Reports on Form 8-K: On December 12, 1995, a report on Form 8-K was filed announcing the Public Service Commission of Kentucky's approval of the Trimble County power plant settlement agreement. -65- SCHEDULE II LOUISVILLE GAS AND ELECTRIC COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 1995 (Thousands of $)
Reserves Deducted from Assets in Balance Sheet --------------------------------- Other Accounts Property Receivable and (Uncollectible Investments Accounts) ----------- -------------- Balance January 1, 1993..................................... $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... Other................................................... 5,815 2,135 ------ ------ 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 Additions: Charged to costs and expenses........................... 3,200 Deductions: Net charges of nature for which reserves were created... 3,043 ------ ------ Balance December 31, 1995................................... $ 63 $1,360 ------ ------ ------ ------
-66- 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 27, 1996 By Walter Z. Berger - -------------- ------------------------------------- (Date) Walter Z. Berger Executive Vice President and Chief Financial Officer 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); WALTER Z. BERGER Executive Vice President and Chief Financial Officer (Principal Financial and 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 Walter Z. Berger March 27, 1996 ----------------------------------- WALTER Z. BERGER (Attorney-In-Fact) -67- EX-3.06 2 EXHIBIT 3.06 LOUISVILLE GAS AND ELECTRIC COMPANY By-Laws Adopted November 7, 1956 As Amended Through December 15, 1995 ARTICLE I MEETINGS OF STOCKHOLDERS SECTION 1. The Annual Meeting of the stockholders of the Company shall be held at a location in or out of Kentucky at a time and date to be fixed by the Board of Directors each year. Notice of the annual meeting shall be mailed to each stockholder entitled to notice at least ten (10) days before the Annual Meeting. SECTION 2. Except as otherwise mandated by Kentucky law and except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company's Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company's Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, special meetings of stockholders may be called only by the President of the Company or by the Board of Directors pursuant to a resolution approved by a majority of the entire Board of Directors. For purposes of these By-Laws, the phrase "Company's Amended Articles of Incorporation" shall mean the Amended Articles of Incorporation of Louisville Gas and Electric Company as in effect on February 1, 1987, and as thereafter amended from time to time. SECTION 3. A stockholder may vote in person or by proxy, filed with the Secretary of the Company before or immediately upon the convening of the meeting. SECTION 4. Any action required or permitted to be taken by the stockholders of the Company at a meeting of such holders may be taken without such a meeting ONLY if a consent in writing setting forth the action so taken shall be signed by all of the stockholders entitled to vote with respect to the subject matter thereof. SECTION 5. At an annual meeting of the stockholders, only such business shall be conducted as shall have been properly brought before the meeting. To be properly brought before an annual meeting, business must be (a) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, (b) otherwise properly brought before the meeting by or at the direction of the Board of Directors, or (c) otherwise properly be requested to be brought before the meeting by a stockholder. For business to be properly requested to be brought before an annual meeting by a stockholder, the stockholder must have given timely notice thereof in writing to the Secretary of the Company. To be timely, a stockholder's notice must be delivered to or mailed and received at the principal executive offices of the Company, not less than 90 days prior to the meeting; provided, however, that in the event that the date of the meeting is not publicly announced by the Company by mail, press release or otherwise more than 100 days prior to the meeting, notice by the stockholder to be timely must be delivered to the Secretary of the Company not later than the close of business on the tenth day following the day on which such announcement of the date of the meeting was communicated to stockholders. A stockholder's notice to the Secretary shall set forth as to each matter the stockholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the name and address, as they appear on the Company's books, of the stockholder proposing such business, (c) the class and number of shares of the Company which are beneficially owned by the stockholder, and (d) any material interest of the stockholder in such business. Notwithstanding anything in the By-Laws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section 5. The Chairman of an annual meeting shall, if the facts warrant, determine and declare to the meeting that business was not properly brought before the meeting and in accordance with the provisions of this Section 5, and if he should so determine, he shall so declare to the meeting that any such business not properly brought before the meeting shall not be transacted. ARTICLE II BOARD OF DIRECTORS SECTION 1. (a) The number of directors of the Company shall be fixed from time to time by the Board of Directors, but shall be no fewer than nine (9) and no more than 15. The Board of Directors may elect one of its members as Chairman of the Board. Regular meetings of the Board of Directors shall be held at such time and place as may be fixed by the Board of Directors. Except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company's Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company's Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, the directors shall be classified, with respect to the time for which they severally hold office, into three classes, as nearly equal in number as possible, as determined by the Board of Directors, one class to be originally elected for a term expiring at the annual meeting of stockholders to be held in 1988, another class to be originally elected for a term expiring at the annual meeting of stockholders to be held in 1989, and another class to be originally elected for a term expiring at the annual meeting of stockholders to be held in 1990, with each member of each class to hold office until his successor is elected and qualified. At each annual meeting of the stockholders of the Company and except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company's Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company's Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, the successors of the class of directors whose term expires at that meeting shall be elected to hold office for a term expiring at the annual meeting of stockholders held in the third year following the year of their election. (b) Advance notice of stockholder nominations for the election of directors shall be given in the manner provided in Section 2 of Article IV of these By-Laws. 2 (c) Except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company's Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company's Common Stock as to dividends or upon liquidation to elect directors under specified circumstances: (i) newly created directorships resulting from any increase in the number of directors and any vacancies on the Board of Directors resulting from death, resignation, disqualification, removal or other cause shall be filled by the affirmative vote of a majority of the remaining directors then in office, even though less than a quorum of the Board of Directors; (ii) any director elected in accordance with the preceding clause (i) shall hold office for the remainder of the full term of the class of directors in which the new directorship was created or the vacancy occurred and until such director's successor shall have been elected and qualified; and (iii) no decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director. (d) Except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company's Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company's Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, any director may be removed from office, with or without cause, only by the affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding shares of the Company's stock entitled to vote generally (as defined in Article Eighth of the Company's Amended Articles of Incorporation), voting together as a single class. Notwithstanding the foregoing provisions of this Paragraph (d), if at any time any stockholders of the Company have cumulative voting rights with respect to the election of directors and less than the entire Board of Directors is to be removed, no director may be removed from office if the votes cast against his removal would be sufficient to elect him as a director if then cumulatively voted at an election of the class of directors of which he is a part. SECTION 2. Regular Meetings shall be held at such time and place as may be fixed by the Board of Directors. SECTION 3. Special Meetings of the Board of Directors shall be held at the call of the Chairman or of the President, or, in their absence, of a Vice President, or at the request in writing of not less than three (3) members of the Board. SECTION 4. Regular and Special Meetings may be held outside of the State of Kentucky. SECTION 5. Notices of Regular and Special Meetings shall be sent to each director at least one (1) day prior to the meeting. SECTION 6. The business and affairs of the Company shall be managed by or under the direction of the Board of Directors, except as may be otherwise provided by law or by the Company's Amended Articles of Incorporation. Unless otherwise provided by law, at each meeting of the Board of Directors, the presence of a majority of the total number of directors shall constitute a quorum for the transaction of business. Except as provided in Section 1(c) of this Article II, the vote of a 3 majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors. In case at any meeting of the Board of Directors a quorum shall not be present, the members of the Board of Directors present may by majority vote adjourn the meeting from time to time until a quorum shall attend. SECTION 7. Directors may receive such fees or compensation for their services as may be authorized by resolution of the Board of Directors. In addition, expenses of attendance, if any, may be allowed for attendance at each regular or special meeting. SECTION 8. The Board of Directors, by resolution adopted by a majority of the full Board of Directors, may designate from among its members an executive committee and one or more other committees each of which, to the extent provided in such resolution, shall have and exercise all the authority of the Board of Directors, but no such committee shall have the authority to take action that under Kentucky law can only be taken by a board of directors. ARTICLE III OFFICERS SECTION 1. The officers of the Company shall be a Chief Executive Officer, President, Chief Financial Officer, one or more Vice Presidents, Secretary, Treasurer, Controller and such other officers (including, if so directed by a resolution of the Board of Directors, Chairman of the Board) as the Board may from time to time elect or appoint. Any two of the offices may be combined in one person, but no officer shall execute, acknowledge, or verify any instrument in more than one capacity. Officers are to be elected by the Board of Directors of the Company at the first meeting of the Board following the annual meeting of stockholders and, unless otherwise specified by the Board of Directors, shall be elected to hold office for one year or until their successors are elected and qualified. Any vacancy shall be filled by the Board of Directors, provided that the Chief Executive Officer may fill such a vacancy until the Board of Directors shall elect a successor. Except as provided below, officers shall perform those duties usually incident to the office or as otherwise required by the Board of Directors, the Chief Executive Officer, or the officer to whom they report. An officer may be removed with or without cause and at any time by the Board of Directors or by the Chief Executive Officer. CHIEF EXECUTIVE OFFICER SECTION 2. The Chief Executive Officer of the Company shall have full charge of all of the affairs of the Company, shall preside at all meetings of the stockholders and, in the absence of the Chairman of the Board, at meetings of the Board of Directors. 4 PRESIDENT SECTION 3. The President shall exercise the functions of the Chief Executive Officer during the absence or disability of the Chief Executive Officer. CHIEF FINANCIAL OFFICER SECTION 4. The Chief Financial Officer of the Company shall have full charge of all of the financial affairs of the Company, including maintaining accurate books and records, meeting all reporting requirements and controlling Company funds. VICE PRESIDENTS SECTION 5. The Vice President or Vice Presidents may be designated as Vice President, Senior Vice President or Executive Vice President, as the Board of Directors or Chief Executive Officer may determine. SECRETARY SECTION 6. The Secretary shall be present at and record the proceedings of all meetings of the Board of Directors and of the stockholders, give notices of meetings of Directors and stockholders, have custody of the seal of the Company and affix it to any instrument requiring the same, and shall have the power to sign certificates for shares of stock of the Company. TREASURER SECTION 7. The Treasurer shall have charge of all receipts and disbursements of the Company and be custodian of the Company's funds. CONTROLLER SECTION 8. The Controller shall have charge of the accounting records of the Company. CHAIRMAN OF THE BOARD SECTION 9. In the event the Board of Directors elects a Chairman of the Board and designates by resolution that the Chairman of the Board shall be an officer of the corporation, the Chairman of the Board shall preside at all meetings of the Board of Directors and serve the corporation in an advisory capacity. 5 ARTICLE IV CAPITAL STOCK CERTIFICATES AND DIRECTOR NOMINATIONS SECTION 1. The Board of Directors shall approve all stock certificates as to form. The certificates for the various classes of stock, issued by the Company, shall be printed or engraved with the facsimile signatures of the President and Secretary and a facsimile seal of the Company. The Board of Directors shall appoint transfer agents to issue and transfer certificates of stock, and registrars to register said certificates. SECTION 2. Except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company's Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company's Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, nominations for the election of directors may be made by the Board of Directors or a committee appointed by the Board of Directors or by any stockholder entitled to vote in the election of directors generally. However, any stockholder entitled to vote in the election of directors generally may nominate one or more persons for election as director or directors at a stockholders' meeting only if written notice of such stockholder's intent to make such nomination or nominations has been given either by personal delivery or by United States mail, postage prepaid, to the Secretary of the Company not later than 90 days in advance of such meeting; provided, however, that in the event the date of the meeting is not publicly announced by the Company by mail, press release or otherwise more than 100 days prior to the meeting, notice by the stockholder to be timely must be delivered not later than the close of business on the tenth day following the date on which notice of such meeting was first communicated to stockholders. Each such notice shall set forth (a) the name and address of the stockholder who intends to make the nomination and of the person or persons to be nominated; (b) a representation that the stockholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice; (c) a description of all arrangements or understandings between the stockholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the stockholder; (d) such other information regarding each nominee proposed by such stockholder as would be required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission, had the nominee been nominated, or intended to be nominated, by the Board of Directors; and (e) the consent of each nominee to serve as a director of the Company if so elected. The Chairman of the meeting may refuse to acknowledge the nomination of any person not made in compliance with the foregoing procedure. 6 ARTICLE V LOST STOCK CERTIFICATES The Board of Directors may, in its discretion, direct that a new certificate or certificates of stock be issued in place of any certificate or certificates of stock theretofore issued by the Company, alleged to have been stolen, lost or destroyed, and the Board of Directors when authorizing the issuance of such new certificate or certificates may, in its discretion, and as a condition precedent thereto, require the owner of such stolen, lost or destroyed certificate or certificates or the legal representatives of such owner, to give to the Company, its transfer agent or agents, its registrar or registrars, as may be authorized or required to sign and countersign such new certificate or certificates, a corporate surety bond in such sum as it may direct as indemnity against any claim or claims that may be made against the Company, its transfer agent or agents, its registrar or registrars, for or in respect to the shares of stock represented by the certificate or certificates alleged to have been stolen, lost or destroyed. ARTICLE VI DIVIDENDS ON PREFERRED STOCK Dividends upon the 5% Cumulative Preferred Stock, $25 Par value, if declared, shall be payable on January 15, April 15, July 15 and October 15 of each year. If the date herein designated for the payment of any dividend shall, in any year, fall upon a legal holiday, then the dividend payable on such date shall be paid on the next day not a legal holiday. Dividends in respect of each share of $8.90 Cumulative Preferred Stock (without par value) of the Company shall be payable on October 16, 1978, when and as declared by the Board of Directors of the Company, to holders of record on September 29, 1978, and shall accrue from the date of original issuance of said series. Thereafter, such dividends shall be payable on January 15, April 15, July 15, and October 15 in each year (or the next business day thereafter in each case), when and as declared by the Board of Directors of the Company, for the quarter-yearly period ending on the last business day of the preceding month. Dividends in respect of each share of Preferred Stock, Auction Series A (without par value), of the Company shall be payable when and as declared by the Board of Directors of the Company, on the dates and in the manner set forth in the Amendment to the Articles of Incorporation of the Company setting forth the terms of such series. Dividends in respect of each share of $5.875 Cumulative Preferred Stock, of the Company shall be payable when and as declared by the Board of Directors of the Company, on the dates and in the manner set forth in the Amendment to the Articles of Incorporation of the Company setting forth the terms of such series. 7 ARTICLE VII FINANCE SECTION 1. The Board of Directors shall designate the bank or banks to be used as depositories of the funds of the Company and shall designate the officers and employees of the Company who may sign and countersign checks drawn against the various accounts of the Company. The Board of Directors may authorize the use of facsimile signatures on checks drawn against certain bank accounts of the Company. SECTION 2. Notes shall be signed by the President and either a Vice President or the Treasurer. In the absence of the President, notes shall be signed by two Vice Presidents, or a Vice President and the Treasurer. ARTICLE VIII SEAL The seal of this Company shall be in the form of a circular disk, bearing the following information: (Louisville Gas and Electric Company) ( Incorporated Under the Laws of ) ( Kentucky ) ( Seal ) ( 1913 ) ARTICLE IX AMENDMENTS Subject to the provisions of the Company's Amended Articles of Incorporation, these By-Laws may be amended or repealed at any regular meeting of the stockholders (or at any special meeting thereof duly called for that purpose) by the holders of at least a majority of the voting power of the shares represented and entitled to vote thereon at such meeting at which a quorum is present; provided that in the notice of such special meeting notice of such purpose shall be given. Subject to the laws of the State of Kentucky, the Company's Amended Articles of Incorporation and these By-Laws, the Board of Directors may by majority vote of those present at any meeting at which a quorum is present amend these By-Laws, or adopt such other By-Laws as in their judgment may be advisable for the regulation of the conduct of the affairs of the Company. 8 ARTICLE X INDEMNIFICATION SECTION 1. RIGHT TO INDEMNIFICATION. Each person who was or is a director of the Company and who was or is made a party or is threatened to be made a party to or is otherwise involved (including, without limitation, as a witness) in any action, suit or proceeding, whether civil, criminal, administrative or investigative (hereinafter a "proceeding"), by reason of the fact that he or she is or was a director or officer of the Company or is or was serving at the request of the Company as a director, officer, partner, trustee, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (hereinafter an "Indemnified Director"), whether the basis of such proceeding is alleged action in an official capacity as a director or officer or in any other capacity while serving as a director or officer, shall be indemnified and held harmless by the Company to the fullest extent permitted by the Kentucky Business Corporation Act, as the same exists or may hereafter be amended, against all expense, liability and loss (including, without limitation, attorneys' fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) reasonably incurred or suffered by such Indemnified Director in connection therewith and such indemnification shall continue as to an Indemnified Director who has ceased to be a director or officer and shall inure to the benefit of the Indemnified Director's heirs, executors and administrators. Each person who was or is an officer of the Company and not a director of the Company and who was or is made a party or is threatened to be made a party to or is otherwise involved (including, without limitation, as a witness) in any proceeding, by reason of the fact that he or she is or was an officer of the Company or is or was serving at the request of the Company as a director, officer, partner, trustee, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (hereinafter an "Indemnified Officer"), whether the basis of such proceeding is alleged action in an official capacity as an officer or in any other capacity while serving as an officer, shall be indemnified and held harmless by the Company against all expense, liability and loss (including, without limitation, attorneys' fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) reasonably incurred or suffered by such Indemnified Officer to the same extent and under the same conditions that the Company must indemnify an Indemnified Director pursuant to the immediately preceding sentence and to such further extent as is not contrary to public policy and such indemnification shall continue as to an Indemnified Officer who has ceased to be an officer and shall inure to the benefit of the Indemnified Officer's heirs, executors and administrators. Notwithstanding the foregoing and except as provided in Section 2 of the this Article X with respect to proceedings to enforce rights to indemnification, the Company shall indemnify any Indemnified Director or Indemnified Officer in connection with a proceeding (or part thereof) initiated by such Indemnified Director or Indemnified Officer only if such proceeding (or part thereof) was authorized by the Board of Directors of the Company. As hereinafter used in this Article X, the term "indemnitee" means any Indemnified Director or Indemnified Officer. Any person who is or was a director or officer of a subsidiary of the Company shall be deemed to be serving in such capacity at the request of the Company for purposes of this Article X. The right to 9 indemnification conferred in this Article shall include the right to be paid by the Company the expenses incurred in defending any such proceeding in advance of its final disposition (hereinafter an "advancement of expenses"); provided, however, that, if the Kentucky Business Corporation Act requires, an advancement of expenses incurred by an indemnitee who at the time of receiving such advance is a director of the Company shall be made only upon: (i) delivery to the Company of an undertaking (hereinafter an "undertaking"), by or on behalf of such indemnitee, to repay all amounts so advanced if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (hereinafter, a "final adjudication") that such indemnitee is not entitled to be indemnified for such expenses under this Article or otherwise; (ii) delivery to the Company of a written affirmation of the indemnitee's good faith belief that he has met the standard of conduct that makes indemnification by the Company permissible under the Kentucky Business Corporation Act; and (iii) a determination that the facts then known to those making the determination would not preclude indemnification under the Kentucky Business Corporation Act. The right to indemnification and advancement of expenses incurred in this Section 1 shall be a contract right. SECTION 2. RIGHT OF INDEMNITEE TO BRING SUIT. If a claim under Section 1 of this Article X is not paid in full by the Company within sixty days after a written claim has been received by the Company (except in the case of a claim for an advancement of expenses, in which case the applicable period shall be twenty days), the indemnitee may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim. If successful in whole or in part to any such suit or in a suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the indemnitee also shall be entitled to be paid the expense of prosecuting or defending such suit. In (i) any suit brought by the indemnitee to enforce a right to indemnification hereunder (other than a suit to enforce a right to an advancement of expenses brought by an indemnitee who will not be a director of the Company at the time such advance is made) it shall be a defense that, and in (ii) any suit by the Company to recover an advancement of expenses pursuant to the terms of an undertaking the Company shall be entitled to recover such expenses upon a final adjudication that, the indemnitee has not met the standard of conduct that makes it permissible hereunder or under the Kentucky Business Corporation Act (the "applicable standard of conduct") for the Company to indemnify the indemnitee for the amount claimed. Neither the failure of the Company (including its Board of Directors, independent legal counsel or its stockholders) to have made a determination prior to the commencement of such suit that indemnification of the indemnitee is proper in the circumstances because the indemnitee has met the applicable standard of conduct, nor an actual determination by the Company (including its Board of Directors, independent legal counsel or its stockholders) that the indemnitee has not met the applicable standard of conduct, shall create a presumption that the indemnitee has not met the applicable standard of conduct or, in the case of such a suit brought by the indemnitee, be a defense to such suit. In any suit brought by the indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the indemnitee is not entitled to be indemnified or to such advancement of expenses under this Article X or otherwise shall be on the Company. 10 SECTION 3. NON-EXCLUSIVITY OF RIGHTS. The rights to indemnification and to the advancement of expenses conferred in this Article X shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, the Company's Articles of Incorporation, these By-Laws, any agreement, any vote of stockholders or disinterested directors or otherwise. SECTION 4. INSURANCE. The Company may maintain insurance, at its expense, to protect itself and any director, officer, employee or agent of the Company or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss, whether or not the Company would have the power to indemnify such person against such expense, liability or loss under the Kentucky Business Corporation Act. SECTION 5. INDEMNIFICATION OF EMPLOYEES AND AGENTS. The Company may, to the extent authorized from time to time by the Board of Directors, grant rights to indemnification and to the advancement of expenses to any employee or agent of the Company and to any person serving at the request of the Company as an agent or employee of another corporation or of a partnership, joint venture, trust or other enterprise to the fullest extent of the provisions of this Article X with respect to the indemnification and advancement of expenses of directors and officers of the Company. SECTION 6. REPEAL OR MODIFICATION. Any repeal or modification of any provision of this Article X shall not adversely affect any rights to indemnification and to advancement of expenses that any person may have at the time of such repeal or modification with respect to any acts or omissions occurring prior to such repeal or modification. SECTION 7. SEVERABILITY. In case any one or more of the provisions of this Article X, or any application thereof, shall be invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions of this Article X, and any other application thereof, shall not in any way be affected or impaired thereby. 11 EX-10.43 3 EXHIBIT 10.43 - ------------------------------------------------------------------------------- MODIFICATION NO. 8 TO INTER-COMPANY POWER AGREEMENT DATED JULY 10, 1953 AMONG OHIO VALLEY ELECTRIC CORPORATION, APPALACHIAN POWER COMPANY, THE CINCINNATI GAS & ELECTRIC COMPANY, COLUMBUS SOUTHERN POWER COMPANY (formerly COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY), THE DAYTON POWER AND LIGHT COMPANY, INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY), KENTUCKY UTILITIES COMPANY, LOUISVILLE GAS AND ELECTRIC COMPANY MONONGAHELA POWER COMPANY, OHIO EDISON COMPANY, OHIO POWER COMPANY, PENNSYLVANIA POWER COMPANY, THE POTOMAC EDISON COMPANY, SOUTHERN INDIANA GAS AND ELECTRIC COMPANY, THE TOLEDO EDISON COMPANY, and WEST PENN POWER COMPANY. ----------------------------- Dated as of January 19, 1994 ----------------------------- - ------------------------------------------------------------------------------- MODIFICATION NO. 8 TO INTER-COMPANY POWER AGREEMENT THIS AGREEMENT dated as of the _____ day of __________, 1994, by and among OHIO VALLEY ELECTRIC CORPORATION (herein called "OVEC" or "Corporation"), APPALACHIAN POWER COMPANY (herein called "Appalachian"), THE CINCINNATI GAS & ELECTRIC COMPANY (herein called "Cincinnati"), COLUMBUS SOUTHERN POWER COMPANY (formerly COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY) (herein called "Columbus"), THE DAYTON POWER AND LIGHT COMPANY (herein called "Dayton"), INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY) (herein called "Indiana"), KENTUCKY UTILITIES COMPANY (herein called "Kentucky"), LOUISVILLE GAS AND ELECTRIC COMPANY (herein called "Louisville"), MONONGAHELA POWER COMPANY (herein called "Monongahela"), OHIO EDISON COMPANY (herein called "Ohio Edison"), OHIO POWER COMPANY (herein called "Ohio Power"), PENNSYLVANIA POWER COMPANY (herein called "Pennsylvania"), THE POTOMAC EDISON COMPANY (herein called "Potomac"), SOUTHERN INDIANA GAS AND ELECTRIC COMPANY (herein called "Southern Indiana"), THE TOLEDO EDISON COMPANY (herein called "Toledo"), and WEST PENN POWER COMPANY (herein called "West Penn"), all of the foregoing, other than OVEC, being herein sometimes collectively referred to as the Sponsoring Companies and individually as a Sponsoring Company. 2 W I T N E S S E T H T H A T WHEREAS, Corporation and the United States of America have heretofore entered into Contract No. AT-(40-1)-1530 (redesignated Contract No. E-(40-1)- 1530, later redesignated Contract No. EY-76-C-05-1530 and later redesignated Contract No. DE-AC05-760RO1530), dated October 15, 1952, providing for the supply by Corporation of electric utility services to the United States Atomic Energy Commission (hereinafter called "AEC") at AEC's project near Portsmouth, Ohio (hereinafter called the "Project"), which Contract has heretofore been modified by Modification No. 1, dated July 23, 1953, Modification No. 2, dated as of March 15, 1964, Modification No. 3, dated as of May 12, 1966, Modification No. 4, dated as of January 7, 1967, Modification No. 5, dated as of August 15, 1967, Modification No. 6, dated as of November 15, 1967, Modification No. 7, dated as of November 5, 1975, Modification No. 8, dated as of June 23, 1977, Modification No. 9, dated as of July 1, 1978, Modification No. 10, dated as of August 1, 1979, Modification No. 11, dated as of September 1, 1979, Modification No. 12, dated as of August 1, 1981, Modification No. 13, dated as of September 1, 1989, Modification No. 14, dated as of January 15, 1992, and Modification No. 15, dated as of February 1, 1993 (said Contract, as so modified, is hereinafter called the "DOE Power Agreement"); and WHEREAS, pursuant to the Energy Reorganization Act of 1974, the AEC was abolished on January 19, 1975 and certain of its functions, including the procurement of electric utility services for the Project, were transferred to and vested in the Administrator of Energy Research and Development; and WHEREAS, pursuant to the Department of Energy Organization Act, on October 1, 1977, all of the functions vested by law in the Administrator of Energy Research and Development or the 3 Energy Research and Development Administration were transferred to, and vested in, the Secretary of Energy, the statutory head of the Department of Energy (hereinafter called "DOE"); and WHEREAS, the parties hereto have entered into a contract, herein called the "Inter-Company Power Agreement," dated July 10, 1953, governing, among other things, (a) the supply by the Sponsoring Companies of Supplemental Power in order to enable Corporation to fulfill its obligations under the DOE Power Agreement, and (b) the rights of the Sponsoring Companies to receive Surplus Power (as defined in the Agreement identified in the next clause in this preamble) as may be available at the Project Generating Stations and the obligations of the Sponsoring Companies to pay therefor; and WHEREAS, the Inter-Company Power Agreement has heretofore been amended by Modification No. 1, dated as of June 3, 1966, Modification No. 2 dated as of January 7, 1967, Modification No. 3, dated as of November 15, 1967, Modification No. 4, dated as of November 5, 1975, Modification No. 5, dated as of September 1, 1979, Modification No. 6, dated as of August 1, 1981, and Modification No. 7, dated as of January 15, 1992 (said contract so amended and as modified and amended by this Modification No. 8 being herein and therein sometimes called the "Agreement"); and WHEREAS, OVEC and the Sponsoring Companies desire to enter into this Modification No. 8 as more particularly hereinafter provided; NOW, THEREFORE, the parties hereto agree with each other as follows: 1. Insert after SUBSECTION 1.0122 a new SUBSECTION 1.0123 as follows: 1.0123 "Emergency Power Supply Period" means any period of time during which, at the request of one or more of the Sponsoring Companies, OVEC and DOE have agreed to reduce the contract demand under the DOE Power Agreement in order that one or more of the Sponsoring Companies will have available additional Surplus 4 Power and Energy to prevent or alleviate an emergency which impairs or jeopardizes the ability of the Sponsoring Company or Companies to meet load. 2. Delete SUBSECTION 5.041 and substitute therefor the following: 5.041 Any Sponsoring Company's Surplus Power Reservation, established as hereinbelow provided, shall remain in effect for a period of not less than a calendar week except during an Emergency Power Supply Period. Surplus Power Reservations shall provide the basis for carrying out settlements between OVEC and Sponsoring Companies. 3. Delete SECTION 6.01 and substitute therefor the following: 6.01 TOTAL MONTHLY CHARGE. The amount to be paid Corporation each month by he Sponsoring Companies for Surplus Power and Surplus Energy supplied under this Agreement shall consist of the sum of an energy charge, a demand charge and, if applicable, an emergency power surcharge, all determined as set forth in this ARTICLE 6. 4. Delete SUBSECTION 6.035 and substitute therefor the following: 6.035 Determine the difference, if any, between (a) the aggregate of the costs determined as provided in subsection 6.031 above and (b) the sum of the demand charge to be charged to DOE determined as provided in subsection 6.033 above plus the amounts (other than amounts for fuel expense), if any, payable by DOE pursuant to paragraph 3 of Section 2.04 of the DOE Power Agreement for billing kwh of supplemental energy furnished from the Project Generating Stations. The aggregate demand charge which shall be paid by or credited to all Sponsoring Companies for such month shall be the amount of such difference. The portion thereof payable for such month by each Sponsoring Company shall be computed by allocating such aggregate demand charge, based on availability on a kilowatt-hour basis, among the calendar weeks (or fractions thereof) of such month and shall be the total of the products obtained by multiplying the respective Surplus power Reservations of said Sponsoring Company for such weeks (or fraction thereof) by the respective amounts so allocated. 5. Insert after SUBSECTION 6.035 a new SUBSECTION 6.036 as follows: 6.036 If, during an Emergency Power Supply Period, OVEC requests DOE to reduce load so that more capacity and energy can be made available to a Sponsoring Company or Companies affected by such emergency and if DOE agrees to do so on condition that OVEC reimburse DOE for its estimated costs of reducing load (emergency power surcharge), the aggregate demand charge to be paid by each 5 Sponsoring Company shall be adjusted to reflect its agreed share of DOE's emergency power surcharge paid or credited by OVEC to DOE. Such share shall be determined based on DOE's estimated cost per kilowatt of reducing an increment of load during a clock-hour and the amount of capacity reserved by such Sponsoring Company attributable to such load reduction. 6. This modification No. 8 shall become effective at 12:00 o'clock Midnight on the day on which Corporation shall advise the other parties to this Modification No. 8 (to be later confirmed in writing) that all conditions precedent to the effectiveness of this Modification No. 8 shall have been satisfied. 7. The Inter-Company Power Agreement, as modified by Modifications Nos. 1, 2, 3, 4, 5, 6 and 7 and as hereinbefore provided, is hereby in all respects confirmed. 8. This Modification No. 8 may be executed in any number of copies and by the different parties hereto on separate counterparts, each of which shall be deemed an original but all of which together shall constitute a single agreement. IN WITNESS WHEREOF, the parties hereto have executed this Modification No. 8 as of the day and year first written above. OHIO VALLEY ELECTRIC CORPORATION By: ----------------------------------- APPALACHIAN POWER COMPANY By: ----------------------------------- THE CINCINNATI GAS & ELECTRIC COMPANY By: ----------------------------------- 6 COLUMBUS SOUTHERN POWER COMPANY By: ----------------------------------- THE DAYTON POWER AND LIGHT COMPANY By: ----------------------------------- INDIANA MICHIGAN POWER COMPANY By: ----------------------------------- KENTUCKY UTILITIES COMPANY By: ----------------------------------- LOUISVILLE GAS AND ELECTRIC COMPANY By: ----------------------------------- MONONGAHELA POWER COMPANY By: ----------------------------------- OHIO EDISON COMPANY By: ----------------------------------- OHIO POWER COMPANY By: ----------------------------------- PENNSYLVANIA POWER COMPANY By: ----------------------------------- 7 THE POTOMAC EDISON COMPANY By: ----------------------------------- SOUTHERN INDIANA GAS AND ELECTRIC COMPANY By: ----------------------------------- THE TOLEDO EDISON COMPANY By: ----------------------------------- WEST PENN POWER COMPANY By: ----------------------------------- 8 EX-10.44 4 EXHIBIT 10.44 Texas Gas Transmission Corporation 3800 Frederica Street P.O. Box 1160 Owensboro, KY 42302 March 1, 1995 Louisville Gas and Electric Company 820 West Broadway Louisville, Kentucky 40202 Attention: Mr. J. Clay Murphy Gentlemen: Reference is made to the Firm No-Notice Transportation Agreement (Agreement) dated November 1, 1993, as amended, between Texas Gas Transmission Corporation (Texas Gas) and Louisville Gas and Electric Company (LG&E), providing for the transportation of natural gas by Texas Gas for LG&E. Accordingly, Texas Gas and LG&E hereby desire to amend the Agreement between them as follows: A. ARTICLE II, QUANTITY, Sections 2.2, 2.3, and 2.5, for the two-year agreement shall be deleted in their entirety and replaced with the following: 2.2 The maximum daily quantity of gas which Texas Gas shall be obligated to transport and redeliver to Customer, and which Customer shall be obligated to receive, is Customer's applicable Contract Demand expressed on a seasonal basis as set forth below:
Daily Contract Demand MMBtu/d --------------- ------- Winter 61,633 Summer 37,000 Shoulder Month (April) 49,480 Shoulder Month (October) 56,006
2.3 The above Contract Demand consists of a Nominated Daily Quantity, for which Customer is responsible for scheduling the delivery of gas supplies into Texas Gas's system, and an Unnominated Daily Quantity, which is automatically delivered from storage by Texas Gas to meet Customer's requirements. Those quantities, expressed on a seasonal basis, are set forth below:
Nominated Daily Quantity MMBtu/d -------------- ------- Winter 49,000 Summer (except October) 37,000 October 41,000 Unnominated Daily Quantity MMBtu/d -------------- ------- Winter 12,633 Shoulder Month (April) 6,316 Shoulder Month (October) 8,843
2.5 The maximum seasonal quantities of gas which Texas Gas shall be obligated to transport and deliver to Customer, and which Customer shall be obligated to receive, are Customer's Seasonal Quantity Entitlements as set forth below:
Seasonal Quantity Entitlement MMBtu/d -------------------- ------- Winter 8,740,000 Summer 5,314,466
B. ARTICLE II, QUANTITY, Sections 2.2, 2.3, and 2.5, for the five-year agreement shall be deleted in their entirety and replaced with the following: 2.2 The maximum daily quantity of gas which Texas Gas shall be obligated to transport and redeliver to Customer, and which Customer shall be obligated to receive, is Customer's applicable Contract Demand expressed on a seasonal basis as set forth below:
Daily Contract Demand MMBtu/d --------------- ------- Winter 61,633 Summer 37,000 Shoulder Month (April) 49,480 Shoulder Month (October) 56,007
2 2.3 The above Contract Demand consists of a Nominated Daily Quantity, for which Customer is responsible for scheduling the delivery of gas supplies into Texas Gas's system, and an Unnominated Daily Quantity, which is automatically delivered from storage by Texas Gas to meet Customer's requirements. Those quantities, expressed on a seasonal basis, are set forth below:
Nominated Daily Quantity MMBtu/d -------------- ------- Winter 49,000 Summer (except October) 37,000 October 41,000 Unnominated Daily Quantity MMBtu/d -------------- ------- Winter 12,633 Shoulder Month (April) 6,317 Shoulder Month (October) 8,843
2.5 The maximum seasonal quantities of gas which Texas Gas shall be obligated to transport and deliver to Customer, and which Customer shall be obligated to receive, are Customer's Seasonal Quantity Entitlements as set forth below:
Seasonal Quantity Entitlement MMBtu/d -------------------- ------- Winter 8,740,000 Summer 5,314,667
C. ARTICLE II, QUANTITY, Sections 2.2, 2.3, and 2.5, for the eight-year agreement shall be deleted in their entirety and replaced with the following: 2.2 The maximum daily quantity of gas which Texas Gas shall be obligated to transport and redeliver to Customer, and which Customer shall be obligated to receive, is Customer's applicable Contract Demand expressed on a seasonal basis as set forth below: 3
Daily Contract Demand MMBtu/d --------------- ------- Winter 61,633 Summer 37,000 Shoulder Month (April) 49,480 Shoulder Month (October) 56,007
2.3 The above Contract Demand consists of a Nominated Daily Quantity, for which Customer is responsible for scheduling the delivery of gas supplies into Texas Gas's system, and an Unnominated Daily Quantity, which is automatically delivered from storage by Texas Gas to meet Customer's requirements. Those quantities, expressed on a seasonal basis, are set forth below:
Nominated Daily Quantity MMBtu/d -------------- ------- Winter 49,000 Shoulder (except October) 37,000 October 41,000
Unnominated Daily Quantity MMBtu/d -------------- ------- Winter 12,634 Shoulder Month (April) 6,317 Shoulder Month (October) 8,844
2.5 The maximum seasonal quantities of gas which Texas Gas shall be obligated to transport and deliver to Customer, and which Customer shall be obligated to receive, are Customer's Seasonal Quantity Entitlements as set forth below: 4
Seasonal Quantity Entitlement MMBtu/d -------------------- ------- Winter 8,740,000 Summer 5,314,667
D. ARTICLE XI, SHOULDER MONTH FLEXIBILITY, Section 11.1 shall be deleted in its entirety and replaced with the following: 11.1 During the Shoulder Months of April and October, Texas Gas will deliver to Customer at the city-gate the Customer's Shoulder Month Contract Demand, which shall, unless otherwise agreed, be the sum of Customer's Summer Contract Demand, Customer's Excess Unnominated Quantity and the applicable percentage as set forth below of Customer's Unnominated Daily Quantity for the Winter Season:
Percent of Unnominated Shoulder Month Daily Quantity -------------- -------------- April 50% October 70%
In the event that Customer's Unnominated Seasonal Quantity is available in quantities sufficient to support additional access to Customer's Unnominated Daily Quantity the applicable percentage available to Customer during such Shoulder Month will be as follows:
%of Unnominated % of Unnominated Seasonal Quantity Daily Quantity Should Month Withdrawn Available - ------------ --------- --------- April/October 75% 90% 80% 85% 85% 80% 90% 75% 95% 70%
Although such Shoulder Month Contract Demand shall be available during any day of the Shoulder Month, it shall only be available for a maximum of fifteen (15) gas days during such month. 5 E. EXHIBIT "A", FIRM POINT(S) OF RECEIPT, shall be deleted in its entirety and replaced with the attached Winter Season - Exhibit "A", FIRM POINT(S) OF RECEIPT and Summer Season - Exhibit "A", FIRM POINT(S) OF RECEIPT. F. EXHIBIT"C", SUPPLY LATERAL CAPACITY, shall be deleted in its entirety and replaced with the attached Winter Season - Exhibit "C", SUPPLY LATERAL CAPACITY and Summer Season - Exhibit "C", SUPPLY LATERAL CAPACITY. This amendment shall become effective April 1, 1995, and shall remain in force for a term to coincide with the term of the Agreement. The operation of the provisions of this amendment shall be subject to all applicable governmental statutes and all applicable and lawful orders, rules, and regulations. Except as herein amended, the Agreement between the parties hereto shall remain in full force and effect. If the foregoing is in accordance with your understanding of our Agreement, please execute both copies and return to us. We will, in turn, execute them and return one copy for your records. Very truly yours, LOUISVILLE GAS AND ELECTRIC TEXAS GAS TRANSMISSION COMPANY CORPORATION By: By: Title: ATTEST: AGREED TO AND ACCEPTED this _____ day of _____________, 1995. 6 Contract No. N0415 Winter Season - Exhibit "A" Firm Point(s) of Receipt Louisville Gas And Electric Company Firm No-Notice Transportation Agreement
Daily Firm Meter Capacity Lateral Segment Zone No. Name MMBtu - ------------------------------------------------------------------------------------------------- North Louisiana Leg Carthage-Haughton 1 2102 Champlin 16,715 Sharon-East 1 2632 Dubach 13,455 1 8760 Lonewa 15,000 1 2631 Calhoun Plant 5,000 Southeast Leg Blk. 8-Morgan City SL 2845 Lake Pagie 3,007 SL 9471 Sohio 5,743 Henry-Lafayette SL 2790 Henry Hub 26,682 Maurice-Freshwater SL 2840 UNOCAL-N Fresh Water Bayou 18,829 Offshore in at Calumet SL 2550 EI293/308/315 11,592 South Leg Egan-Eunice SL 9003 Egan 19,379
7
Daily Firm Meter Capacity Lateral Segment Zone No. Name MMBtu - ------------------------------------------------------------------------------------------------- Offshore in at Egan SL 2770 Vermilion 267F 2,116 SL 2774 Vermilion 256D 951 SL 9342 Vermilion 255/256E 225 SL 2782 Vermilion 267C 1,254 SL 2781 S.S. 247F 3,592 SL 2776 S.S. 248D 4,811 Southwest Leg Lowry-Eunice SL 9446 NGPL-Lowry 6,161 W.C. 294 Enters at ANR-Eunice SL 9383 WC 293/HI 167/HI 167-166 4,819 HIOS (at ANR-Eunice) H.I. 247 SL 9135 WC167/HIOS Mainline 3,800 H.I. 555 SL 9887 HIA-555/A-557A/A-556 2,000 H.I. 573 SL 2859 HIA-573B COMPLEX 17,743 Mainline Bastrop-North 3 2399 ANR-Slaughters (ref. #8082) 20,000 1 9303 Helena #2 10,000 3 9868 U.Cities-Barnsley (ref. #9404) 12,000 Eunice-Zone SL/1 Line SL 8147 Mamou (ref. #8046) 2,092
8
Daily Firm Meter Capacity Lateral Segment Zone No. Name MMBtu - ------------------------------------------------------------------------------------------------- Zone SL/1 Line-Bastrop 1 2020 Arkla-Perryville 20,000 1 8063 Pineville (LIG) 20,000
This exhibit reflects the combined total receipt point capacity held by Louisville Gas and Electric Company under the 2-year, 5-year and 8-year agreements for Contract No. NO415. Amendments in contract quantities in either the 2-year, 5-year or 8-year agreements will result in an amendment of this exhibit. 9 Contract No. N0415 Summer Season - Exhibit "A" Firm Point(s) of Receipt Louisville Gas And Electric Company Firm No-Notice Transportation Agreement
Daily Firm Meter Capacity Lateral Segment Zone No. Name MMBtu - ------------------------------------------------------------------------------------------------- North Louisiana Leg Carthage-Haughton 1 2102 Champlin 16,715 Sharon-East 1 2631 Calhoun Plant 5,000 1 8760 Lonewa 15,000 1 2632 Dubach 13,455 Southeast Leg Blk. 8-Morgan City SL 9471 Sohio 5,743 SL 2845 Lake Pagie 3,007 Henry-Lafayette SL 2790 Henry Hub 26,682 Maurice-Freshwater SL 2840 UNOCAL-N Fresh Water Bayou 18,829 Offshore in at Calumet SL 2550 EI293/308/315 11,592 South Leg Egan-Eunice SL 9003 Egan 19,379 Southwest Leg Lowry-Eunice SL 9446 NGPL-Lowry 6,161
10
Daily Firm Meter Capacity Lateral Segment Zone No. Name MMBtu - ------------------------------------------------------------------------------------------------- W.C. 294 Enters at ANR-Eunice SL 9383 WC 293/HI 167/HI 167-166 4,819 HIOS (at ANR-Eunice) H.I. 247 SL 9135 WC167/HIOS Mainline 3,800 H.I. 555 SL 9887 HIA-555/A-557A/A-556 2,000 H.I. 573 SL 2859 HIA-573B COMPLEX 5,440 Mainline Bastrop-North 3 2399 ANR-Slaughters (ref. #8082) 20,000 1 9303 Helena #2 10,000 3 9868 U.Cities-Barnsley (ref. #9404) 12,000 Eunice-Zone SL/1 Line SL 8147 Mamou (ref. #8046) 2,092 Zone SL/1 Line-Bastrop 1 2020 Arkla-Perryville 20,000 1 8063 Pineville (LIG) 20,000
This exhibit reflects the combined total receipt point capacity held by Louisville Gas And Electric Company under the 2-year, 5-year, and 8-year agreements for Contract No. N0415. Amendments in contract quantities in either the 2-year, S-year, or 8-year agreements will result in an amendment of this exhibit. 11 Contract No. NO415 Firm No-Notice Transportation Agreement Winter Season-Exhibit "C" Supply Lateral Capacity Louisville Gas and Electric Company
PREFERENTIAL RIGHTS SUPPLY LATERAL MMBtu/d Zone 1 Supply Lateral(s) - ------------------------ North Louisiana Leg: 50,170 -------- Total Zone 1: 50,170 Zone SL Supply Lateral(s) - ------------------------- East Leg: 0 Southeast Leg: 65,853 South Leg: 32,328 Southwest Leg: 22,648 West Leg: 0 WC-294: 4,819 HIOS: 23,543 -------- Total Zone SL: 149,191 -------- Grand Total: 199,361 -------- --------
This exhibit reflects the combined total supply lateral capacity held by Louisville Gas and Electric Company under the 2-year, 5-year and 8-year agreements for Contract No. NO415. Amendments in contract quantities in either the 2-year, 5-year or 8-year agreements will result in an amendment of this exhibit. 12 Contract No. NO415 Firm No-Notice Transportation Agreement Summer Season-Exhibit "C" Supply Lateral Capacity Louisville Gas and Electric Company
PREFERENTIAL RIGHTS SUPPLY LATERAL MMBtu/d Zone 1 Supply Lateral(s) - ------------------------ North Louisiana Leg: 50,170 -------- Total Zone 1: 50,170 Zone SL Supply Lateral(s) - ------------------------- East Leg: 0 Southeast Leg: 65,853 South Leg: 19,379 Southwest Leg: 15,351 West Leg: 0 WC-294: 4,819 HIOS: 11,240 -------- Total Zone SL: 116,642 -------- Grand Total: 166,812 -------- --------
This exhibit reflects the combined total supply lateral capacity held by Louisville Gas and Electric Company under the 2-year, 5-year and 8-year agreements for Contract No. NO415. Amendments in contract quantities in either the 2-year, 5-year or 8-year agreements will result in an amendment of this exhibit. 13 EX-10.45 5 EXHIBIT 10.45 T6487 GAS TRANSPORTATION AGREEMENT BETWEEN TEXAS GAS TRANSMISSION CORPORATION AND LOUISVILLE GAS AND ELECTRIC COMPANY (TERM THROUGH: OCTOBER 31, 1998) DATED MARCH 1, 1995 INDEX ----- ARTICLE I Definitions 1 ARTICLE II Transportation Service 1 ARTICLE III Scheduling 2 ARTICLE IV Points of Receipt and Delivery 3 ARTICLE V Term of Agreement 3 ARTICLE Vl Point(s) of Measurement 3 ARTICLE VII Facilities 4 ARTICLE VIII Rates and Charges 4 ARTICLE IX Miscellaneous 5 EXHIBIT "A" FIRM POINT(S) OF RECEIPT EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT EXHIBIT "B" FIRM POINT(S) OF DELIVERY EXHIBIT "C" SUPPLY LATERAL CAPACITY STANDARD FACILITIES KEY FIRM TRANSPORTATION AGREEMENT THIS AGREEMENT, made and entered into this 1st day of March, 1995, by and between Texas Gas Transmission Corporation, a Delaware corporation, hereinafter referred to as "Texas Gas," and Louisville Gas and Electric Company, a Kentucky corporation, hereinafter referred to as "Customer," WITNESSETH: WHEREAS, Customer has natural gas which cannot be moved into its system/which it desires Texas Gas to move through its existing facilities; and WHEREAS, Texas Gas has the ability in its pipeline system to move natural gas for the account of Customer; and WHEREAS, Customer desires that Texas Gas transport such natural gas for the account of Customer; and WHEREAS, Customer and Texas Gas are of the opinion that the transaction referred to above falls within the provisions of Section 284.223 of Subpart G of Part 284 of the Federal Energy Regulatory Commission's (Commission) regulations and the blanket certificate issued to Texas Gas in Docket No. CP88-686-000, and can be accomplished without the prior approval of the Commission; NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto covenant and agree as follows: ARTICLE I DEFINITIONS 1.1 Definition of Terms of the General Terms and Conditions of Texas Gas's FERC Gas Tariff on file with the Commission is hereby incorporated by reference and made a part of this Agreement. ARTICLE II TRANSPORTATION SERVICE 2.1 Subject to the terms and provisions of this Agreement, Customer agrees to deliver or cause to be delivered to Texas Gas, at the Point(s) of Receipt in Exhibit "A" hereunder, Gas for Transportation, and Texas Gas agrees to receive, transport, and redeliver, at the Point(s) of Delivery in Exhibit "B" hereunder, Equivalent Quantities of Gas to Customer or for the account of Customer, in accordance with Section 3 of Texas Gas's effective FT Rate Schedule and the terms and conditions contained herein, up to 0 MMBtu per day during the winter season, and up to 8,000 MMBtu per day during the summer season, which shall be Customer's Firm Transportation Contract Demand, and up to 0 MMBtu during the winter season, and up to 1,712,000 MMBtu during the summer season, which shall be Customer's Seasonal Quantity Levels. 2.2 Customer shall reimburse Texas Gas for the Quantity of Gas required for fuel, company use, and unaccounted for associated with the transportation service hereunder in accordance with Section 16 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. The applicable fuel retention percentage(s) is shown on Exhibit "A". Texas Gas may adjust the fuel retention percentage as operating circumstances warrant; however, such change shall not be retroactive. Texas Gas agrees to give Customer thirty (30) days written notice before changing such percentage. 2.3 Texas Gas, at its sole option, may, if tendered by Customer, transport daily quantities in excess of the Transportation Contract Demand. 2.4 In order to protect its system, the delivery of gas to its customers and/or the safety of its operations, Texas Gas shall have the right to vent excess natural gas delivered to Texas Gas by Customer or Customer's supplier(s) in that part of its system utilized to transport gas received hereunder. Prior to venting excess gas, Texas Gas will use its best efforts to contact Customer or Customer's supplier(s) in an attempt to correct such excess deliveries to Texas Gas. Texas Gas may vent such excess gas solely within its reasonable judgment and discretion without liability to Customer, and a pro rata share of any gas so vented shall be allocated to Customer. Customer's pro rata share shall be determined by a fraction, the numerator of which shall be the quantity of gas delivered to Texas Gas at the Point of Receipt by Customer or Customer's supplier(s) in excess of Customer's confirmed nomination and the denominator of which shall be the total quantity of gas in excess of total confirmed nominations flowing in that part of Texas Gas's system utilized to transport gas, multiplied by the total quantity of gas vented or lost hereunder. 2.5 Any gas imbalance between receipts and deliveries of gas, less fuel and PVR adjustments, if applicable, shall be cleared each month in accordance with Section 17 of the General Terms and Conditions in Texas Gas's FERC Gas Tariff. Any imbalance remaining at the termination of this Agreement shall also be cashed-out as provided herein. ARTICLE III SCHEDULING 3.1 Customer shall be obligated five (5) working days prior to the end of each month to furnish Texas Gas with a schedule of the estimated daily quantity(ies) of gas it desires to be received, transported, and redelivered for the following month. Such schedules will show the quantity(ies) of gas Texas Gas will receive from Customer at the Point(s) of Receipt, along with the identity of the supplier(s) that is delivering or causing to be delivered to Texas Gas quantities for Customer's account at each Point of Receipt for which a nomination has been made. 3.2 Customer shall give Texas Gas, after the first of the month, at least twenty-four (24) hours notice prior to the commencement of any day in which Customer desires to change the quantity(ies) of gas it has scheduled to be delivered to Texas Gas at the Point(s) of Receipt. Texas Gas agrees to waive this 24-hour prior notice and implement nomination changes requested by Customer to commence in such lesser time frame subject to Texas Gas's being able to confirm and verify such nomination change at both Receipt and Delivery Points, and receive PDAs reflecting this nomination change at both Receipt and Delivery Points. Texas Gas will use its best efforts to make the 2 nomination change effective at the time requested by Customer; however, if Texas Gas is unable to do so, the nomination change will be implemented as soon as confirmation is received. ARTICLE IV POINTS OF RECEIPT, DELIVERY AND SUPPLY LATERAL ALLOCATION 4.1 Customer shall deliver or cause to be delivered natural gas to Texas Gas at the Point(s) of Receipt specified in Exhibit "A" attached hereto and Texas Gas shall redeliver gas to Customer or for the account of Customer at the Point(s) of Delivery specified in Exhibit "B" attached hereto in accordance with Sections 7 and 15 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. 4.2 Customer's preferential capacity rights on each of Texas Gas's supply laterals shall be as set forth in Exhibit "C" attached hereto, in accordance with Section 34 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE V TERM OF AGREEMENT 5.1 This Agreement shall become effective upon its execution and remain in full force and effect with a primary term beginning April 1, 1995, (with the rates and charges described in Article VIII becoming effective on that date) and extending through October 31, 1998. At the end of such primary term, or any subsequent roll-over term of five (5) years, this Agreement shall automatically be extended for an additional roll-over term of five (5) years, unless Customer terminates this Agreement at the end of such primary or roll-over term by giving Texas Gas at least 365 days advance written notice prior to the expiration of the primary term or any subsequent roll-over term. ARTICLE VI POINT(S) OF MEASUREMENT 6.1 The gas shall be delivered by Customer to Texas Gas and redelivered by Texas Gas to Customer at the Point(s) of Receipt and Delivery hereunder. 6.2 The gas shall be measured or caused to be measured by Customer and/or Texas Gas at the Point(s) of Measurement which shall be as specified in Exhibits "A", "A-I", and "B" herein. In the event of a line loss or leak between the Point of Measurement and the Point of Receipt, the loss shall be determined in accordance with the methods described contained in Section 3, "Measuring and Measuring Equipment," contained in the General Terms and Conditions of First Revised Volume No. 1 of Texas Gas's FERC Gas Tariff. ARTICLE VII FACILITIES 3 7.1 Texas Gas and Customer agree that any facilities required at the Point(s) of Receipt, Point(s) of Delivery, and Point(s) of Measurement shall be installed, owned, and operated as specified in Exhibits "A", "A-I", and "B" herein. Customer may be required to pay or cause Texas Gas to be paid for the installed cost of any new facilities required as contained in Sections 1.3, 1.4, and 1.5 of Texas Gas's FT Rate Schedule. Customer shall only be responsible for the installed cost of any new facilities described in this Section if agreed to in writing between Texas Gas and Customer. ARTICLE VIII RATES AND CHARGES 8.1 Each month, Customer shall pay Texas Gas for the service hereunder an amount determined in accordance with Section 5 of Texas Gas's FT Rate Schedule contained in Texas Gas's FERC Gas Tariff, which Rate Schedule is by reference made a part of this Agreement. The maximum rates for such service consist of a monthly reservation charge multiplied by Customer's firm transportation demand as specified in Section 2.1 herein. The reservation charge shall be billed as of the effective date of this Agreement. In addition to the monthly reservation charge, Customer agrees to pay Texas Gas each month the maximum commodity charge up to Customer's Transportation Contract Demand. For any quantities delivered by Texas Gas in excess of Customer's Transportation Contract Demand, Customer agrees to pay the maximum FT overrun commodity charge. In addition, Customer agrees to pay: (a) Texas Gas's Fuel Retention percentage(s). (b) The currently effective GRI funding unit, if applicable, the currently effective FERC Annual Charge Adjustment unit charge (ACA), the currently effective Take-or-Pay surcharge, or any other then currently effective surcharges, including but not limited to Order 636 Transition Costs. If Texas Gas declares force majeure which renders it unable to perform service herein, then Customer shall be relieved of its obligation to pay demand charges for that part of its FT Contract Demand affected by such force majeure event until the force majeure event is remedied. Unless otherwise agreed to in writing by Texas Gas and Customer, Texas Gas may, from time to time, and at any time selectively after negotiation, adjust the rate(s) applicable to any individual Customer; provided, however, that such adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor shall they be less than the Minimum Rate(s) set forth in the currently effective Sheet No. 10 of this Tariff. if Texas Gas so adjusts any rates to any Customer, Texas Gas shall file with the Commission any and all required reports respecting such adjusted rate. 8.2 In the event Customer utilizes a Secondary Point(s) of Receipt or Delivery for transportation service herein, Customer will continue to pay the monthly reservation charges as described in Section 8.1 above. In addition, Customer will pay the maximum commodity charge applicable to the zone in which gas is received and redelivered up to Customer's Transportation Contract Demand and the maximum overrun commodity charge for any quantities delivered by Texas Gas in excess of Customer's winter season or summer season Transportation Contract Demand. Customer also 4 agrees to pay the ACA, Take-or-Pay Surcharge, GRI charges, fuel retention charge, and any other effective surcharges, if applicable, as described in Section 8.1 above. 8.3 It is further agreed that Texas Gas may seek authorization from the Commission and/or other appropriate body for such changes to any rate(s) and terms set forth herein or in Rate Schedule FT, as may be found necessary to assure Texas Gas just and reasonable rates. Nothing herein contained shall be construed to deny Customer any rights it may have under the Natural Gas Act, as amended, including the right to participate fully in rate proceedings by intervention or otherwise to contest increased rates in whole or in part. 8.4 Customer agrees to fully reimburse Texas Gas for all filing fees, if any, associated with the service contemplated herein which Texas Gas is required to pay to the Commission or any agency having or assuming jurisdiction of the transactions contemplated herein. 8.5 Customer agrees to execute or cause its supplier or processor to execute a separate agreement with Texas Gas providing for the transportation of any liquids and/or liquefiables, and agrees to pay or reimburse Texas Gas, or cause Texas Gas to be paid or reimbursed, for any applicable rates or charges associated with the transportation of such liquids and/or liquefiables, as specified in Section 24 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE IX MISCELLANEOUS 9.1 Texas Gas's Transportation Service hereunder shall be subject to receipt of all requisite regulatory authorizations from the Commission, or any successor regulatory authority, and any other necessary governmental authorizations, in a manner and form acceptable to Texas Gas. The parties agree to furnish each other with any and all information necessary to comply with any laws, orders, rules, or regulations. 9.2 Except as may be otherwise provided, any notice, request, demand, statement, or bill provided for in this Agreement or any notice which a party may desire to give the other shall be in writing and mailed by regular mail, or by postpaid registered mail, effective as of the postmark date, to the post office address of the party intended to receive the same, as the case may be, or by facsimile transmission, as follows: TEXAS GAS --------- Texas Gas Transmission Corporation 3800 Frederica Street Post Office Box 1160 Owensboro, Kentucky 42302 Attention: Gas Revenue Accounting (Billings and Statements) Customer Services (Other Matters) Gas Transportation and Capacity Allocation (Nominations) Fax (502) 926-8686 5 CUSTOMER -------- Louisville Gas and Electric Company 820 West Broadway Louisville, Kentucky 40202 Attention: Mr. J. Clay Murphy The address of either party may, from time to time, be changed by a party mailing, by certified or registered mail, appropriate notice thereof to the other party. Furthermore, if applicable, certain notices shall be considered duly delivered when posted to Texas Gas's Electronic Bulletin Board, as specified in Texas Gas's tariff. 9.3 This Agreement shall be governed by the laws of the State of Kentucky. 9.4 Each party agrees to file timely all statements, notices, and petitions required under the Commission's Regulations or any other applicable rules or regulations of any governmental authority having jurisdiction hereunder and to exercise due diligence to obtain all necessary governmental approvals required for the implementation of this Transportation Agreement. 9.5 All terms and conditions of Rate Schedule FT and the attached Exhibits "A", "A-l", "B", and "C" are hereby incorporated to and made a part of this Agreement. 9.6 This contract shall be binding upon and inure to the benefit of the successors, assigns, and legal representatives of the parties hereto. 9.7 Neither party hereto shall assign this Agreement or any of its rights or obligations hereunder without the consent in writing of the other party. Notwithstanding the foregoing, either party may assign its right, title and interest in, to and by virtue of this Agreement including any and all extensions, renewals, amendments, and supplements thereto, to a trustee or trustees, individual or corporate, as security for bonds or other obligations or securities, without such trustee or trustees assuming or becoming in any respect obligated to perform any of the obligations of the assignor and, if any such trustee be a corporation, without its being required by the parties hereto to qualify to do business in the state in which the performance of this Agreement may occur, nothing contained herein shall require consent to transfer this Agreement by virtue of merger or consolidation of a party hereto or a sale of all or substantially all of the assets of a party hereto, or any other corporate reorganization of a party hereto. 9.8 This Agreement insofar as it is affected thereby, is subject to all valid rules, regulations and orders of all governmental authorities having jurisdiction. 9.9 No waiver by either party of any one or more defaults by the other in the performance of any provisions hereunder shall operate or be construed as a waiver of any future default or defaults whether of a like or a different character. 6 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective representatives thereunto duly authorized, on the day and year first above written. ATTEST: TEXASGAS TRANSMISSION CORPORATION - ---------------------------------- By: ------------------------------ WITNESSES: LOUISVILLE GAS AND ELECTRIC COMPANY By: - ---------------------------------- ------------------------------ Attest: - ---------------------------------- --------------------------- Date of Execution by Customer: - ---------------------------------- 7 Contract No. T6487 Summer Season - Exhibit "A" Firm Point(s) of Receipt Louisville Gas And Electric Company Firm Transportation Agreement
Daily Firm Meter Capacity Lateral Segment Zone No. Name MMBtu - ------------------------------------------------------------------------------- South Leg Offshore in at Egan SL 2770 Vermillion 267F 2,116 SL 2782 Vermillion 267C 1,254 SL 2774 Vermillion 256D 951 SL 9342 Vermillion 255/256E 225 SL 2776 S.S. 248D 4,811 SL 2781 S.S. 247F 3,592 HIOS (at ANR-Eunice) H.I. 573 SL 2859 HIA-573B COMPLEX 12,303
This exhibit reflects the combined total receipt point capacity held by Louisville Gas And Electric Company under the 2-year, 5-year, and 8-year agreements for Contract No. T6487. Amendments in contract quantities in either the 2-year, 5-year, or 8-year agreements will result in an amendment of this exhibit. 8 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT SUPPLY
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- NORTH LOUISIANA Carthage-Haughton 1 2102 Champlin 1 9805 Delhi 1 9051 Grigsby 1 9860 Nelson-Greenwood/Waskom 1 8116 Texas Eastern-Sligo 1 9884 Valero-Carthage Haughton-Sharon 1 8003 Barksdale 1 2455 Beacon 1 9866 Cornerstone-Ada 1 2173 Crystal Oil-West Arcadia 1 2340 F.E. Hargraves-Minden 1 2186 LGI #1 1 2456 McCormick 1 2457 Minden-Hunt 1 2459 Minden Pan-Am #1 1 9819 Nelson-Sibley 1 9461 Olin-McGoldrick 1 2760 Sligo Plant 1 9834 Texaco-Athens
9
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- Sharon 1 2010 Fina Oil-HICO 1 9818 PGC-Bodcaw 1 2757 Texas Eastern-Sharon Sharon-East 1 2631 Calhoun Plant 1 2632 Dubach 1 2202 Ergon-Monroe 1 8760 Lonewa 1 8020 MRT-Bastrop 1 9302 Munce 1 9812 Par Minerals/Downsville 1 9823 Reliance-Bernice 1 2612 Reliance-West Monroe 1 2634 Southwest-Guthrie EAST Bosco-Eunice SL 2015 Amerada Hess SL 2016 Amerada Hess-South Lewisburg SL 2385 D.B. McClinton #1 SL 9844 Germany Oil-Church Point SL 2288 Great Southern-Mowata #2 SL 9804 Great Southern-Mowata #3 SL 2289 Great Southern-South Lewisburg SL 8142 Ritchie SL 9119 Sevarg SL 2740 Superior-Pure
10
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- SOUTHEAST Blk. 8-Morgan City SL 2198 Bois D'Arc SL 9142 Bois D'Arc-Pelican Lake SL 2109 Chevron-Block 8 SL 2638 Coon Point SL 2845 Lake Pagie SL 9817 Mustang-Bayou Piquant SL 2460 Peltex Deep Saline #1 SL 2480 S.S. 41 SL 9471 Sohio SL 9888 Star Oil & Gas-Bay Junop SL 9187 Stone-South Timbalier SL 2755 Texaco-Bay Junop SL 9836 Texaco-Dog Lake SL 2463 Toce Oil SL 2850 Union Oil-N. Lake Pagie SL 9883 Zeit-Lake Pagie Henry-Lafayette SL 8190 Faustina-Henry SL 2790 Henry Hub Lafayette-Eunice SL 2153 Branch-Cox SL 2125 California Co.-North Duson SL 2137 California Co.-South Bosco #1 SL 2138 California Co.-South Bosco #2
11
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- SL 2600 Cayman-Anslem Coulee SL 9852 CNG-South Rayne SL 2389 Duson SL 9837 Excel-Judice SL 8068 Exch. O&G-No. Maurice SL 2601 Fina Oil-Anslem Coulee SL 8040 Florida SL 2290 Gulf Transport-Church Pt. SL 2148 Maurice Cox SL 9906 Quintana-South Bosco SL 9005 Rayne-Columbia Gulf SL 2045 Riceland-North Tepetate SL 8067 South Scott SL 2810 Tidewater-North Duson SL 8051 Youngsville Maurice-Freshwater SL 9822 Cities Service-Nunez SL 2147 CNG-Hell Hole Bayou SL 2203 Deck Oil-Perry/Hope SL 9808 Duhon/Parcperdue SL 9044 EDC-N. Parcperdue SL 9160 LLOG-Abbeville SL 2394 LRC-Theall SL 9800 May Petroleum SL 2424 McCain-Maurice SL 2748 Parc Perdue
12
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- SL 2749 Parc Perdue 2 SL 9830 R&R Res-Abbeville SL 2706 Sun Ray SL 9422 UNOCAL-Freshwater Bayou SL 2840 UNOCAL-N. Freshwater Bayou Morgan City-Lafayette SL 2064 Amoco-Charenton SL 9173 ANR-Calumet (Rec.) SL 9803 Atlantic SL 9809 B.H. Petroleum-S.E. Avery SL 2080 Bayou Sale-British Am SL 9881 Bridgeline-Berwick SL 2085 British American-Ramos SL 9425 Charenton SL 9047 Florida Gas-E.B. Pigeon SL 2454 FMP/Bayou Postillion SL 8059 Franklin SL 2208 Frantzen SL 9898 Hadson-East Bayou Pigeon SL 2188 Lamson SL 9854 Linder Oil-Bayou Penchant SL 9853 Linder Oil-Garden City SL 2189 Rutledge Deas SL 2636 Shell-Bayou Pigeon SL 9902 Smith Production-Charenton SL 2035 Southwest-Jeanerette
13
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- SL 9895 Texaco-Bayou Sale SL 8205 Transco-Myette Point SL 9829 Trunkline-Centerville SL 9350 Vulcan SL 9835 W.T. Burton-Lake Palourde Offshore Points entering at SL 2583 E.I. 273A Calumet SL 2158 E.I. 273A/273A/284B SL 2584 E.I. 273B SL 2834 E.I. 276C SL 2771 E.I. 287D SL 2151 E.I. 292B SL 9339 E.I. 292B/286I SL 9419 E.I. 292B/286I/293 SL 2550 E.I. 293/308/315 SL 2773 E.I. 307E SL 2154 E.I. 309C SL 2155 E.I. 309G SL 2157 E.I. 309H SL 9886 E.I. 309H/309H/309J SL 2156 E.I. 314F/309C/314F SL 2780 SMI 11C SL 2425 SMI 161 SL 2783 S.S. 204/219
14
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- Thibodaux-Morgan City SL 2250 A. Glassell-Chacahoula SL 2047 Alliance Exploration SL 9029 Coastal-Chacahoula SL 2835 Lake Palourde SL 9873 Linder Oil-Chacahoula SL 9175 LLOG-Chacahoula SL 9847 LRC-Choctaw SL 2440 Magna-Chacahoula #1 SL 2445 Magna-St. John #2 SL 2470 Patterson-Chacahoula SL 2135 Simon Pass SOUTH Egan-Eunice SL 9851 Booher-Iota SL 9003 Egan Offshore Points Entering at SL 9130 E.I. 278/S.S. 247F Egan SL 9131 E.I. 278/S.S. 248D SL 9128 E.I. 299/S.S. 271A SL 9129 E.I. 299/S.S. 271A/S.S. 271B SL 9423 E.I. 320/324 SL 9122 E.I. 320/325A SL 9123 E.I. 342/366A SL 2793 E.I. 342/372A SL 9399 E.I. 342/384A
15
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- SL 2767 E.I. 342C SL 2786 E.I. 343B SL 9363 E.I. 349/349A SL 9364 E.I. 349/349A/349B SL 2788 E.I. 365 SL 9369 E.I. 365A/365A/348 SL 9120 E.I. 372A SL 2781 S.S. 247F SL 2776 S.S. 248D SL 9429 S.S. 248D/248G SL 2778 S.S. 271A SL 2785 S.S. 271B/271A/271B SL 9427 Vermilion 248/255A/255H SL 9342 Vermilion 255/256E SL 9424 Vermilion 255/256E/268G SL 2774 Vermilion 256D SL 9105 Vermilion 267/275A SL 9340 Vermilion 267/287A SL 9341 Vermilion 267/287A/276 SL 9159 Vermilion 267/287A/277 SL 9374 Vermilion 267/289A SL 2782 Vermilion 267C SL 2770 Vermilion 267F SOUTHWEST East Cameron-Lowry SL 9872 E.C. 9A
16
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- SL 2581 E.C. 14 SL 2860 Lake Arthur SL 2033 Little Cheniere-Arco SL 2034 Little Cheniere-Linder SL 2392 LRC-Grand Cheniere Lowry-Eunice SL 9843 Mobil-Lowry SL 9446 NGPL-Lowry SL 2437 ENOGEX/NGPL Tap Washita SL 9169 TEX SW/NGPL Washita SL 9171 Transok/NGPL Inter #2 Beckham SL 9170 Transok/NGPL Inter #2 Custer SL 9172 Transok/NGPL Waggs Wheeler WEST Iowa-Eunice SL 2091 Caribbean-China #1 SL 2092 Caribbean-China #2 SL 2093 Caribbean-China #3 SL 9038 Coastal/ANR-Iowa SL 9839 Great Southern-Woodlawn SL 8170 Iowa SL 9445 Kilroy Riseden-Woodlawn SL 9186 Linder Oil-Woodlawn SL 9890 Source Petroleum-S. Elton #1 SL 9896 Source Petroleum-S. Elton #2 SL 2883 Tree Oil-Woodlawn
17
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- Mallard Bay-Woodlawn SL 2140 California Co.-South Thornwell SL 2615 Caroline Hunt Sands-S. Thornwell SL 2170 Cockrell-North Chalkley SL 9828 Denovo-Lake Arthur SL 2207 Franks Petroleum-Chalkley SL 9028 Gas Energy Development-Hayes SL 2355 Humble-Chalkley SL 2383 IMC Wintershall-Chalkley SL 9848 Lamson Onshore-Mallard Bay SL 8071 LRC-Mallard Bay SL 2701 Samedan-N. Chalkley SL 2635 Shell-Chalkley SL 2266 South Mallard Bay-America1 SL 2822 Superior-S. Thornwell SL 9879 Total Minatome-Bell City SL 2885 Union Texas-Welsh SL 2853 Welsh Field W.C. 294 Entering at ANR-Eunice SL 9026 W.C. 167/132 SL 9135 W.C. 167/HIOS Mainline SL 9136 W.C. 167/Near Shore SL 9396 W.C. 293/H.I. 120/H.I. 120-128 SL 9383 W.C. 293/H.I. 167/H.I. 167-166 SL 2838 W.C. 294
18
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- HIOS Offshore Points Entering at H.I. 247 ANR-Eunice SL 2868 H.I. A-247/A-244A/A-231 SL 9176 H.I. A-247/A-245 H.I. 283 SL 9894 H.I. A-283/A-283A SL 2855 H.I. A-285/A-282 H.I. 303 SL 2858 H.I. A-302A/A-303 H.I. A-345 SL 2863 H.I. 334A/A-335 SL 9327 H.I. A-345/A-325A H.I. A-498 SL 2867 H.I. A-462 SL 9375 H.I. A-477/A-462/A-486 SL 2534 H.I. A-498/A-489 SL 2533 H.I. A-498/A-489/A-474 SL 2535 H.I. A-498/A-489/A-499 SL 9371 H.I. A-498/A-490 SL 2856 H.I. A-498/A-517 H.I. A-539 SL 2537 H.I. A-539/A-480 SL 9365 H.I. A-539/A-511 SL 9376 H.I. A-539/A-532
19
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- SL 9328 H.I. A-539/A-550 SL 9901 H.I. A-539/A-552/A-551 SL 9889 H.I. A-539/A-552/A-553 SL 2539 H.I. A-539/A-567 SL 9380 H.I. A-539/A-568 H.I. A-555 SL 2857 H.I. A-531A SL 2861 H.I. A-536C SL 2862 H.I. A-537B SL 9127 H.I. A-537B/A-537D/A-556 SL 9308 H.I. A-555 SL 9125 H.I. A-555/A-537D/A-556 SL 9887 H.I. A-555/A-557A/A-556 H.I. A-573 SL 9909 H.I. A-573/A-384/G B 224 SL 2859 H.I. A-573B Complex SL 2542 H.I. A-595CF Complex H.I. A-582 SL 9165 H.I. A-582/A-561A SL 9133 H.I. A-582/E.B. 110 SL 9377 H.I. A-582/E.B. 160/Various SL 9134 H.I. A-582/E.B. 165 MAINLINE Bastrop-North 3 8082 ANR-Slaughters 3 2061 Bee-Hunter
20
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- 3 2072 Blair 2 8124 Dyersburg 3 2373 Har-Ken/Addison-G #1 3 2352 Har-Ken/Cox 3 2367 Har-Ken/I.C.C. #9 3 2376 Har-Ken/I.C.C. #12 3 2379 Har-Ken/I.C.C. #15 3 2022 Har-Ken/I.C.C. #16 3 2381 Har-Ken/I.C.C. #17 3 9530 Har-Ken/Murray 3 2362 Har-Ken/P. Gannon Est. #1 3 2351 Har-Ken/Qualls 3 2966 Har-Ken/Stearman #1 3 2960 Har-Ken/W. Ky. #1 3 2962 Har-Ken/W. Ky. #2 3 2375 Har-Ken/W. Ky. #6 3 2087 Heathville-Trenton 1 9303 Helena #2 3 9876 Hux Oil-Russellville 4 1715 Lebanon-Columbia 4 1247 Lebanon-Congas 4 1859 Lebanon-Texas Eastern 3 9527 Liberty-South Hill 3 8073 Midwestern-Whitesville 1 3801 Pooling Receipt-Zone 1 3 9525 Pride Energy No. 1
21
Meter Lateral Segment Zone No. Supply Point - ------------------------------------------------------------------------------- 3 9141 Reynolds-Narge Creek 3 5800 Slaughters-Storage Complex (Withdraw) 1 2648 Spears 3 9404 United Cities-Barnsley Eunice-Zone SL/1 Line SL 9035 ANR-Eunice SL 9084 Bayou Pompey SL 8107 Evangeline SL 8046 Mamou SL 3800 Pooling Receipt-Zone SL SL 3900 SL Lateral Terminus Zone SL/1 Line-Bastrop 1 2020 Arkla-Perryville 1 9870 Channel Explo.-Chicksaw Creek 1 9826 Delhi-Ewing 1 2361 Guffey-Millhaven 1 9877 Hadson-Olla/Summerville 1 9814 Hogan-Davis Lake 1 8063 Pineville (LIG) 1 9832 Wintershall-Clarks
22 CONTRACT NO. T6487 Contract Demand 8,000 MMBtu/D EXHIBIT "B" POINT(S) OF DELIVERY
Meter MAOP MDP* No. Name/Description Facilities (psig) (psig) - ------------------------------------------------------------------------------- 1529 Louisville Gas and Electric Company BARDSTOWN ROAD - Latitude 38-12-0, Longitude 85-36-0, Jefferson County, KY (1) 674 400 BEDFORD-LG&E-Latitude 38-34-30, Longitude 85-18-15, Trimble County, KY (1) 810 400 CRESTWOOD-LG&E-Latitude 38-20-0, Longitude 85-25-15, Oldham County, KY (1) 810 400 DOE RUN-Latitude 37-55-30, Longitude 86-2-30, Meade County, KY (1) 810 400 ELDER PARK-Latitude 38-22-0, Longitude 85-25-0, Oldham County, KY (1) 810 400 ELLINGSWORTH LANE-Latitude 38-13-15 Longitude 85-33-0, Jefferson County, KY (1) 810 350 LA GRANGE-Latitude 38-24-0, Longitude 85-24-15, Oldham County, KY (1) 810 400 PENILE ROAD-Latitude 38-6-0, Longitude 85-47-0, Jefferson County, KY (1) 674 400 PRESTON STREET ROAD-Latitude 38-9-45, Longitude 85-41-30, Jefferson County, KY (1) 674 400
23 Contract No. T6487 Firm Transportation Agreement Summer Season-Exhibit "C" Supply Lateral Capacity Louisville Gas and Electric Company
PREFERENTIAL RIGHTS SUPPLY LATERAL MMBTU/D Zone 1 Supply Lateral(s) - ------------------------ North Louisiana Leg: 0 ------- Total Zone 1: 0 Zone SL Supply Lateral(s) - ------------------------- East Leg: 0 Southeast Leg: 0 South Leg: 12,949 Southwest Leg: 7,297 West Leg: 0 WC-294: 0 HIOS: 12,303 ------- Total Zone SL: 32,549 ------- Grand Total: 32,549 ------- -------
This exhibit reflects the combined total supply lateral capacity held by Louisville Gas and Electric Company under the 2-year, 5-year and 8-year agreements for Contract No. T6487. Amendments in contract quantities in either the 2-year, 5-year or 8-year agreements will result in an amendment of this exhibit. 24 STANDARD FACILITIES KEY (1) Measurement facilities are owned, operated, and maintained by Texas Gas Transmission Corporation. (2) Measurement facilities are owned, operated, and maintained by ANR Pipeline Company. (3) Measurement facilities are owned, operated, and maintained by Arkansas Louisiana Gas Company. (4) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Kerr-McGee Corporation. (5) Measurement facilities are owned, operated, and maintained by Koch Gateway Pipeline Company. (6) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Delhi Gas Pipeline Corporation. (7) Measurement facilities are owned, operated, and maintained by Kerr-McGee Corporation. (8) Measurement facilities are owned, operated, and maintained by Louisiana Intrastate Gas Corporation. (9) Measurement facilities are owned, operated, and maintained by Trunkline Gas Company. (10) Measurement facilities are owned, operated, and maintained by Columbia Gulf Transmission Company. (11) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Columbia Gulf Transmission Company. (12) Measurement facilities are owned, operated, and maintained by Florida Gas Transmission Company. (13) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by ANR Pipeline Company. (14) Measurement facilities are owned by Champlin Petroleum Company and operated and maintained by ANR Pipeline Company. (15) Measurement facilities are owned by Transcontinental Gas Pipe Line Corporation and operated and maintained by ANR Pipeline Company. (16) Measurement facilities are jointly owned by others and operated and maintained by ANR Pipeline Company. 25 (17) Measurement facilities are owned by Koch Gateway Pipeline Company and operated and maintained by ANR Pipeline Company. (18) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Texas Eastern Transmission Corporation. (19) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Natural Gas Pipeline Company of America. (20) Measurement facilities are owned by Louisiana Intrastate Gas Corporation and operated and maintained by Texas Gas Transmission Corporation. (21) Measurement facilities are owned, operated, and maintained by Texas Eastern Transmission Corporation. (22) Measurement facilities are owned by Kerr-McGee Corporation and operated and maintained by ANR Pipeline Company. (23) Measurement facilities are operated and maintained by ANR Pipeline Company. (24) Measurement facilities are owned, operated, and maintained by Transcontinental Gas Pipe Line Corporation. (25) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Tennessee Gas Pipeline Company. (26) Measurement facilities are owned, operated, and maintained by Northern Natural Gas Company. (27) Measurement facilities are owned and maintained by Faustina Pipeline Company and operated by Texas Gas Transmission Corporation. (28) Measurement facilities are owned by Samedan and operated and maintained by ANR Pipeline Company. (29) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by CNG Producing. (30) Measurement facilities are owned, operated, and maintained by Devon Energy Corporation. (31) Measurement facilities are owned by Total Minatome Corporation and operated and maintained by Texas Gas Transmission Corporation. (32) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Trunkline Gas Company. 26 (33) Measurement facilities are owned by Linder Oil Company and operated and maintained by Texas Gas Transmission Corporation. (34) Measurement facilities are owned, operated, and maintained by Mississippi River Transmission Corporation. (35) Measurement facilities are owned, operated, and maintained by Texaco Inc. (36) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Louisiana Resources Company. (37) Measurement facilities are owned, operated, and maintained by Louisiana Resources Company. (38) Measurement facilities are owned by Oklahoma Gas Pipeline Company and operated and maintained by ANR Pipeline Company. (39) Measurement and interconnecting pipeline facilities are owned and maintained by Louisiana Resources Company. The measurement facilities are operated and flow controlled by Texas Gas Transmission Corporation. (40) Measurement facilities are owned by Hall-Houston and operated and maintained by ANR Pipeline Company. (41) Measurement facilities are owned, operated, and maintained as specified in Exhibit "B". (42) Measurement facilities are owned by Enron Corporation and operated and maintained by Texas Gas Transmission Corporation. (43) Measurement facilities are owned by United Cities Gas Company and operated and maintained by TXG Engineering, Inc. (44) Measurement facilities are owned, operated, and maintained by NorAm Gas Transmission Company. (45) Measurement facilities are owned by Falcon Seaboard Gas Company and operated and maintained by Texas Gas Transmission Corporation. (46) Measurement facilities are owned by ANR Pipeline Company and operated and maintained by High Island Offshore System. (47) Measurement facilities are owned by Forest Oil Corporation, et al., and operated and maintained by Tenneco Gas Transportation Company. (48) Measurement facilities are owned by PSI, Inc., and operated and maintained by ANR Pipeline Company. 27 (49) Measurement facilities are owned, operated, and maintained by Tennessee Gas Pipeline Company. (50) Measurement facilities are owned, operated, and maintained by Colorado Interstate Gas Company. (51) Measurement facilities are owned by Producer's Gas Company and operated and maintained by Natural Gas Pipeline Company of America. (52) Measurement facilities are owned by Zapata Exploration and operated and maintained by ANR Pipeline Company. (53) Measurement facilities are jointly owned by Amoco, Mobil, and Union; operated and maintained by ANR Pipeline Company. (54) Measurement facilities are owned, operated, and maintained by VHC Gas Systems, L.P. (55) Measurement facilities are owned by Walter Oil and Gas and operated and maintained by Columbia Gulf Transmission Company. (56) Measurement facilities are operated and maintained by Natural Gas Pipeline Company of America. (57) Measurement facilities are operated and maintained by Texas Gas Transmission Corporation. (58) Measurement facilities are operated and maintained by Tennessee Gas Pipeline Company. (59) Measurement facilities are operated and maintained by Columbia Gulf Transmission Company. (60) Measurement facilities are owned, operated, and maintained by Midwestern Gas Transmission Company. (61) Measurement facilities are owned, operated, and maintained by Western Kentucky Gas Company. 28 EX-10.46 6 EXHIBIT 10.46 CONTRACT #95-348-026 COAL SUPPLY AGREEMENT This is a coal supply agreement (the "Agreement") dated January 1, 1996 between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West Main Street, Louisville, Kentucky 40202 ("Buyer") and LAFAYETTE COAL COMPANY, an Illinois corporation, 200 Frontage Road, Burr Ridge, Illinois 60521 and BLACK BEAUTY COAL COMPANY, an Indiana corporation, 414 S. Fares Avenue, Evansville, Indiana 47702 (collectively "Seller"). The parties hereto agree as follows: SECTION 1. GENERAL. Seller will sell to Buyer and Buyer will buy from Seller steam coal under all the terms and conditions of this Agreement. SECTION 2. TERMINATION OF CURRENT AGREEMENT; TERM. Section 2.1 TERMINATED AGREEMENT. The Coal Supply Agreement dated August 2, 1989 between the parties, as amended (the "Terminated Agreement"), shall be terminated effective December 31, 1995. Section 2.2 TERM. The term of this Agreement shall commence on January 1, 1996 and shall continue through December 31, 1997. Buyer shall have the right to extend the term hereof through December 31, 2000 with a Base Quantity in the amount of 500,000 tons per year, subject to the parties reaching an agreement on price for the coal sold during such extended term. CONTRACT #95-348-026 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) ---- -------------------- 1996 560,000 1997 560,000 Section 3.2 DELIVERY SCHEDULE. 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 pursuant to a reasonable schedule. 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. Section 3.3 ADJUSTMENTS. Buyer may either decrease or increase the Base Quantity for each year by up to 15% by giving to Seller notice of such adjustment by December 1 of the previous year, except that (1) the variation in tonnage between the adjusted Base Quantity and the adjusted Base Quantity from the preceding year under this Agreement or the Terminated Agreement will not exceed 15%, and (2) the adjusted Base Quantity shall not exceed 644,000 tons or be less than 476,000 tons for any year. 2 CONTRACT #95-348-026 SECTION 4. SOURCE. Section 4.1 SOURCE. The coal sold hereunder, including coal purchased by Seller from third parties, shall be supplied from Indiana geological seams 5, 6 and 7, Columbia Mine, Pike County, Indiana and Enterprise Mine, Gibson County, Indiana (the "Coal Property"). Section 4.2 ASSURANCE OF OPERATION AND RESERVES. Seller represents and warrants that the Coal Property contains economically recoverable coal of a quality and in quantities which will be sufficient to satisfy all the requirements of this Agreement. 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 of 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 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 3 CONTRACT #95-348-026 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, in the event that Seller is unable to produce or obtain coal from the Coal Property in the quantity and of the quality required by this Agreement, and such inability is not caused by a force majeure event as defined in Section 10, then Buyer will have the option of requiring that Seller supply substitute coal from other facilities and mines under all the terms and conditions of this Agreement including, but not limited to, the price provisions of Section 8, the quality specifications of Section 6.1, and the provisions of Section 5 concerning reimbursement to Buyer for increased transportation costs. Seller's delivery of coal not produced from the Coal Property without having received the express written consent of Buyer shall constitute a material breach of this Agreement. SECTION 5. DELIVERY. The coal shall be delivered to Buyer F.O.B. barge at the Evansville Terminal dock at mile point 784.0 on the Ohio River (the "Delivery Point"). Seller may deliver the coal at a location different from the Delivery Point, provided, however, that Seller shall reimburse Buyer for any resulting increases in the cost of transporting the coal to Buyer's generating stations. Any resulting savings in such transportation costs shall be retained by Buyer. Title to and risk of loss 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 4 CONTRACT #95-348-026 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 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 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 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 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 5 CONTRACT #95-348-026 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 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. SECTION 6. QUALITY. Section 6.1 SPECIFICATIONS. (a) If Buyer nominates "Washed Coal" pursuant to Section 6.1(b), then the coal delivered hereunder shall conform to the following specifications on an "as received" basis: WASHED COAL -----------
Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) - ---------------------------------------------------------------------------- BTU/LB. min. 11,250 LESS THAN10,700 LBS/MMBTU: --------- MOISTURE max. 12.25 GREATER THAN14.25 ASH max. 8.25 GREATER THAN10.0 SULFUR max. 2.75 GREATER THAN3.2 SULFUR min. 1.7 LESS THAN1.7 CHLORINE max. .03 GREATER THAN.04 NITROGEN max. 1.6 GREATER THAN2.8 ASH/SULFUR RATIO min. 2.2 LESS THAN2.0 Size (3" x 0"): 6 CONTRACT #95-348-026 Top size (inches)* max. 3.0" GREATER THAN3.0" Fines (% by wgt) Passing 1/4" screen max. 32% GREATER THAN35% % BY WEIGHT: ----------- VOLATILE max. 34 GREATER THAN35 VOLATILE min. 30 LESS THAN29 FIXED CARBON max. 45 GREATER THAN47 FIXED CARBON min. 42 LESS THAN40 GRINDABILITY (HGI) min. 54 LESS THAN52 BASE ACID RATIO (B/A) SLAGGING FACTOR** max. 1.9 GREATER THAN2.1 FOULING FACTOR*** max. 0.3 GREATER THAN0.44 ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857) ---------------------------------------- REDUCING ATMOSPHERE ------------------- Initial Deformation min. 2050 min. 2020 Softening (H=W) min. 2210 min. 2190 Softening (H=1/2W) min. 2400 min. 2290 Fluid min. 2475 min. 2350 OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2500 min. 2480 Softening (H=W) min. 2600 min. 2550 Softening (H=1/2W) min. 2620 min. 2610 Fluid min. 2640 min. 2620
* 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 (R(s))=(B/A) x (Percent Sulfur by Weight(Dry)) *** Fouling Factor (R(f))=(B/A) x (Percent Na(2)0 by Weight(Dry)) 7 CONTRACT #95-348-026 The Base Acid Ratio (B/A) is herein defined as: BASE ACID RATIO (B/A) = (FE(2)0(3) + CA0 + MG0 + NA(2)0 + K(2)0) ---------------------------------------- (Si0(2) + A1(2)0(3) + T10(2)) Note: As used herein GREATER THAN means greater than: LESS THAN means less than. If Buyer nominates "Blend Coal" pursuant to Section 6.1(b), then the coal delivered hereunder shall conform to the following specifications on an "as received" basis: BLEND COAL ----------
Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) - ---------------------------------------------------------------------------- BTU/LB. min. 11,200 LESS THAN10,700 LBS/MMBTU: --------- MOISTURE max. 12.00 GREATER THAN14.25 ASH max. 9.00 GREATER THAN11.0 SULFUR max. 3.05 GREATER THAN3.4 SULFUR min. 1.7 LESS THAN1.7 CHLORINE max. .03 GREATER THAN.04 NITROGEN max. 1.6 GREATER THAN2.8 ASH/SULFUR RATIO min. 2.2 LESS THAN2.0 Size (3" x 0"): Top size (inches)* max. 3.0" GREATER THAN3.0" Fines (% by wgt) Passing 1/4" screen max. 32% GREATER THAN35% % BY WEIGHT: ----------- VOLATILE max. 34 GREATER THAN35 VOLATILE min. 30 LESS THAN29 FIXED CARBON max. 45 GREATER THAN47 FIXED CARBON min. 42 LESS THAN40 GRINDABILITY (HGI) min. 54 LESS THAN52 8 CONTRACT #95-348-026 BASE ACID RATIO (B/A) SLAGGING FACTOR** max. 1.9 GREATER THAN2.1 FOULING FACTOR*** max. 0.3 GREATER THAN0.44 ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857) ---------------------------------------- REDUCING ATMOSPHERE ------------------- Initial Deformation min. 2050 min. 2020 Softening (H=W) min. 2210 min. 2190 Softening (H=1/2W) min. 2400 min. 2290 Fluid min. 2475 min. 2350 OXIDIZING ATMOSPHERE -------------------- Initial Deformation min. 2500 min. 2480 Softening (H=W) min. 2600 min. 2550 Softening (H=1/2W) min. 2620 min. 2610 Fluid min. 2640 min. 2620
* 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 (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(2)0(3) + CA0 + MG0 + NA(2)0 + K(2)0) ---------------------------------------- (Si0(2) + A1(2)0(3) + T10(2)) Note: As used herein GREATER THAN means greater than: LESS THAN means less than. 9 CONTRACT #95-348-026 (b) Buyer shall have the right to receive either all Washed Coal or all Blend Coal or both Washed Coal and Blend Coal in any ratio Buyer desires hereunder at Buyer's option subject to the pricing provisions set forth in Section 8.1. Buyer may change such nomination or such ratio at any time by giving to Seller thirty (30) days prior written notice of such change. Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall mean one barge load or a barge lot load in accordance with Buyer's sampling and analyzing practices. Section 6.3 REJECTION. Buyer has the right, but not the obligation, to reject any shipment which fail(s) to conform to the Rejection Limits set forth in Section 6.1 or contains extraneous materials. Buyer must reject such coal within seventy-two (72) hours of receipt of the coal analysis provided for in Section 7.2 or such right to reject is waived. In the event Buyer rejects such non-conforming coal, Buyer shall return the coal to Seller or, at Seller's request, divert such coal to Seller's designee, all at Seller's cost. Seller shall replace the rejected coal within five (5) working days from notice of rejection with coal conforming to the Rejection Limits set forth in Section 6.1. If Seller fails to replace the rejected coal within such five (5) working day period or the replacement coal is rightfully rejected, Buyer may purchase coal from another source in order to replace the rejected coal. Seller shall reimburse Buyer for (i) any amount by which the actual price plus transportation costs to Buyer of such coal purchased from another source exceed the price of such coal under this Agreement plus transportation costs to 10 CONTRACT #95-348-026 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, than such non-conforming coal shall be deemed accepted by Buyer; however, the quantity Seller is obligated to sell to Buyer under the Agreement may or may not be reduced by the amount of each such non-conforming shipment at Buyer's sole option and the Shipment shall nevertheless be considered "rejectable" under Section 6.4. 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 the coal sold hereunder fails to meet one or more of the Guaranteed Monthly Weighted Averages set forth in Section 6.1 for any three (3) consecutive months in a six (6) month period, or if nine (9) barge shipments in a 30 day period are rejectable by Buyer, Buyer may upon notice confirmed in writing and sent to Seller by certified mail, suspend future shipments except shipments already loaded into barges. Seller shall, within 10 days, provide Buyer with reasonable assurances that subsequent monthly deliveries of coal shall 11 CONTRACT #95-348-026 meet or exceed the Guaranteed Monthly Weighted Averages set forth in Section 6.1 and that the source will exceed 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 10 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 any of the Guaranteed Monthly Weighted Averages for any one (1) month within the next six (6) months or if three (3) barge shipments are rejectable within any one (1) month during such six (6) 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 method is mutually agreed upon by the parties. Such scales shall be duly reviewed 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 over 12 CONTRACT #95-348-026 or under the tolerance range allowable for the scale based on industry accepted standards, 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 industry-accepted standards. Samples for analyses shall be taken by any 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. Each sample taken by Buyer shall be divided into 4 parts and put into airtight containers, properly labeled and sealed. One part shall be used for analysis by Buyer; one part shall be used by Buyer as a check sample, if Buyer in its sole judgment determines it is necessary; one part shall be retained by Buyer until the 25th of the month following the 13 CONTRACT #95-348-026 month of unloading (the "Disposal Date") and shall be delivered to Seller for analysis if Seller so requests before the Disposal Date; and one part ("Referee Sample") shall be retained by Buyer until the Disposal Date. Seller shall be given copies of all analyses made by Buyer by the 12th day of the month following the month of unloading. Seller, on reasonable notice to Buyer shall have the right to have a representative present to observe the sampling and analyses performed by Buyer. Unless Seller requests a Referee Sample analysis before the Disposal Date, Buyer's analysis shall be used to determine the quality of the coal delivered hereunder. The Monthly Weighted Averages shall be determined by utilizing the individual shipment analyses. If any dispute arises before the Disposal Date, the Referee Sample retained by Buyer shall be submitted for analysis to an independent commercial testing laboratory ("Independent Lab") mutually chosen by Buyer and Seller. For each coal quality specification in question, a dispute shall be deemed not to exist and Buyer's analysis shall prevail and the analysis of the Independent Lab shall be disregarded if the analysis of the Independent Lab differs from the analysis of Buyer by an amount equal to or less than: (i) 0.50% moisture (ii) 0.50% ash on a dry basis (iii) 100 Btu/lb. on a dry basis (iv) 0.10% sulfur on a dry basis. For each coal quality specification in question, if the analysis of the Independent Lab differs from the analysis of Buyer by an amount more than the amounts listed above, then the analysis of the Independent Lab shall prevail and Buyer's analysis shall be disregarded. 14 CONTRACT #95-348-026 The cost of the analysis made by the Independent Lab shall be borne by Seller to the extent that Buyer's analysis prevails and by Buyer to the extent that the analysis of the Independent Lab prevails. SECTION 8. PRICE. Section BASE PRICE. Subject to Section 8.4, the base price ("Base Price") of the coal to be sold hereunder will be firm and will be $.79000/MMBTU for Washed Coal and $.77500/MMBTU for Blend Coal. Section 8.2 QUALITY PRICE DISCOUNTS. (a) The Base Price is based on coal meeting or exceeding the Guaranteed Monthly Weighted Average specifications as set forth in Section 6.1. Quality price discounts shall be applied for each specification each month to reflect failures to meet the Guaranteed Monthly Weighted Averages set forth in Section 6.1, as determined pursuant to Section 7.2, subject to the provisions set forth below. The discount values used are as follows: DISCOUNT VALUES --------------- $/MMBTU ------- BTU/LB. 0.2604 $/LB./MMBTU ----------- SULFUR 0.1232 ASH 0.0083 MOISTURE 0.0016 (b) Notwithstanding the foregoing, for each specification each month, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. However, if the actual Monthly Weighted Average fails to meet such 15 CONTRACT #95-348-026 applicable Discount Point, then the discount shall apply and shall be calculated on the basis of the difference between the actual Monthly Weighted Average AND THE GUARANTEED MONTHLY WEIGHTED AVERAGE pursuant to the methodology shown in Exhibit A attached hereto.
WASHED COAL ----------- Guaranteed Monthly Weighted Average Discount Point ---------------- -------------- BTU/LB min. 11,250 11,000 LB/MMBTU: --------- SULFUR max. 2.75 3.0 ASH max. 8.25 9.5 MOISTURE max. 12.25 13.75 BLEND COAL ---------- Guaranteed Monthly Weighted Average Discount Point ---------------- -------------- BTU/LB min. 11,200 10,900 LB/MMBTU: --------- SULFUR max. 3.05 3.30 ASH max. 9.00 10.50 MOISTURE max. 12.00 13.50
16 CONTRACT #95-348-026 For example, for Washed Coal, if the actual Monthly Weighted Average of sulfur equals 3.05 lb/MMBTU, then the applicable discount would be (3.05 lb. - 2.75 lb.) X $.1232/lb/MMBTU = $.03696/MMBTU. Section 8.3 PAYMENT CALCULATION. Exhibit A attached hereto shows the methodology for calculating the coal payment and quality price discounts for the month Seller's coal was unloaded by Buyer. If there are any such discounts, Buyer shall apply credit to amounts owed Seller for the month the coal was unloaded. Section 8.4 GOVERNMENTAL IMPOSITIONS. 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. No price adjustment shall be made for costs occasioned by any such taxes, fees, costs and the like in effect on the effective date of this Agreement. In the event of any one enactment, promulgation or change in any statute, regulation, or the like or of any one governmental imposition enacted or promulgated after the effective date of this Agreement, which increases or decreases the Seller's total costs of performance hereunder by at least $.10 per ton, Seller shall give Buyer prompt written notice thereof, including the amount of increase or decrease in cost and notice of proportionate adjustment in Base Price, including the furnishing to Buyer of all computations, data and information reasonably necessary to substantiate such notice. 17 CONTRACT #95-348-026 Buyer shall have the right to audit and inspect Seller's books and records for the purpose of evaluating such notice. The Base Price shall be adjusted in accordance with the notice subject to revision based upon an audit by Buyer. SECTION 9. INVOICES, BILLING AND PAYMENT. Section 9.1 INVOICING ADDRESS. Invoices will be sent to Buyer at the following address: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Manager, Coal Supply With a copy to: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Manager, Accounts Payable Section 9.2 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice Buyer at the Base Price, minus any quality price discounts, for all coal unloaded in a calendar month by the fifteenth of the following month. Section 9.3 PAYMENT PROCEDURES FOR COAL SHIPMENTS. Payment for coal unloaded in a calendar month shall be mailed by the 25th of the month following the month of unloading or within ten days after receipt of Seller's invoice, whichever is later. Buyer shall mail all payments to Seller's account at Lafayette Coal Company, P.O. Box 95580, Chicago, Illinois 60694. 18 CONTRACT #95-348-026 Section 9.4 WITHHOLDING. Buyer shall have the right to withhold from payment of any billing or billings (i) any sums which it is not able in good faith to verify or which it otherwise in good faith disputes, (ii) any damages resulting from or likely to result from any breach of this Agreement by Seller, and (iii) any amounts owed to Buyer from Seller. Buyer shall notify Seller promptly in writing of any such issue, stating the basis of its claim and the amount it intends to withhold. Payment by Buyer, whether knowing or inadvertent, of any amount in dispute shall not be deemed a waiver of any claims or rights by Buyer with respect to any disputed amounts or payments made. SECTION 10. FORCE MAJEURE. 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. 19 CONTRACT #95-348-026 During any period in which Seller's ability to perform hereunder is affected by a force majeure event, Seller shall not deliver any coal from the Coal Property 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. During any period in which Buyer's ability to perform hereunder is affected by a force majeure event, Buyer shall not take delivery of any coal from any other sellers from whom Buyer's ability to take delivery 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 take delivery from Seller under this Agreement of at least a pro rata portion (on a per ton basis) of its total contractual commitments to all its sellers from whom Buyer's ability to take delivery 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 may be made up by mutual agreement of Buyer and Seller on a reasonable schedule. 20 CONTRACT #95-348-026 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 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 21 CONTRACT #95-348-026 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 price per ton of coal, or in any other provision of this Agreement, an equitable adjustment shall be made in: 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. SECTION 12. NOTICES. Section 12.1 FORM AND PLACE OF NOTICE. Any official notice, request for approval or other document required to be given under this Agreement shall be in writing, unless otherwise provided herein, and shall be deemed to have been sufficiently given when delivered in person, transmitted by facsimile or other electronic media, delivered to an established mail service for same day or overnight delivery, or dispatched in the United States mail, postage 22 CONTRACT #95-348-026 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: Lafayette Coal Company 200 Frontage Road Burr Ridge, Illinois 60521 AND Black Beauty Coal Company 414 S. Fares Avenue Evansville, Indiana 47702 Attn: Senior Vice President - Marketing 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. 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. 23 CONTRACT #95-348-026 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. If this Agreement is terminated early in whole, then 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 the termination date of this Agreement as set forth in Section 2. For example, if Seller terminates this Agreement in whole effective December 31, 1996, then Seller would owe Buyer $1,960,000 under this Section 13. If this Agreement is terminated early in part, then the price paid for such early termination shall be $3.50 times the total tonnage terminated from the effective date of the early termination until the termination date of this Agreement as set forth in Section 2. For example, if Seller terminates this Agreement in part effective December 31, 1996 by reducing the Base Quantity from 560,000 to 300,000 tons, then Seller would owe Buyer $910,000 under this Section 13. This provision is not intended to limit, liquidate, or otherwise affect in any manner damages recoverable for breach of this Agreement. SECTION 14. RIGHT TO RESELL. Buyer shall have the unqualified right to sell all or any of the coal purchased under this Agreement. 24 CONTRACT #95-348-026 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 inside and outside attorney's fees) (i) relating to the barges provided by Buyer or Buyer's contractor while such barges 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 carry insurance coverage with minimum limits as follows: (1) Commercial General Liability, including Completed Operations and Contractual Liability, $1,000,000 single limit liability. (2) Automobile General Liability, $1,000,000 single limit liability. (3) In addition, Seller shall carry excess liability insurance covering the foregoing perils in the amount of $4,000,000 for any one occurrence. (4) Workers' Compensation and Employer's Liability with statutory limits. If any of the above policies are written on a claims made basis, then the retroactive date of the policy or policies will be no later than the effective date of this Agreement. Certificates of Insurance satisfactory in form to the Buyer and signed by the Seller's insurer 25 CONTRACT #95-348-026 shall be supplied by the Seller to the Buyer evidencing that the above insurance is in force and that not less than 30 calendar days written notice will be given to the Buyer prior to any cancellation or material reduction in coverage under the policies. The Seller shall cause its insurer to waive all subrogation rights against the Buyer respecting all losses or claims arising from performance hereunder. Evidence of such waiver satisfactory in form and substance to the Buyer shall be exhibited in the Certificate of Insurance mentioned above. Seller's liability shall not be limited to its insurance coverage. SECTION 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. 26 CONTRACT #95-348-026 SECTION 17. DOCUMENTATION AND RIGHT OF AUDIT. Seller shall maintain all records and accounts pertaining to payments, quantities, quality analyses, and source for 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 18. 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). 27 CONTRACT #95-348-026 SECTION 19. COAL PROPERTY INSPECTIONS. Buyer and its representatives, and others as may be required by applicable laws, ordinances and regulations shall have the right at all reasonable times and at their own expense to inspect the Coal Property, including the loading facilities, scales, sampling system(s), wash plant facilities, and mining equipment for conformance with this Agreement. Seller shall undertake reasonable care and precautions to prevent personal injuries to any representatives, agents or employees of Buyer (collectively, "Visitors") who inspect the Coal Property. Any such Visitors shall make every reasonable effort to comply with Seller's regulations and rules regarding conduct on the work site, made known to Visitors prior to entry, as well as safety measures mandated by state or federal rules, regulations and laws. Buyer understands that coal mines and related facilities are inherently high-risk environments. Buyer's failure to inspect the Coal Property or to object to defects therein at the time Buyer inspects the same shall not relieve Seller of any of its responsibilities nor be deemed to be a waiver of any of Buyer's rights hereunder. SECTION 20. MISCELLANEOUS. Section 20.1 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 20.2 HEADINGS. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning or interpretation of this Agreement. 28 CONTRACT #95-348-026 Section 20.3 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 20.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement shall be cumulative and in addition to other remedies provided under this Agreement or by law or in equity. Section 20.5 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 20.6 BINDING EFFECT. This Agreement shall bind and inure to the benefit of the parties and their successors and assigns. Section 20.7 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. 29 CONTRACT #95-348-026 Section 20.8 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 20.9 AMENDMENTS. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by both parties hereto. SECTION 21. JOINT AND SEVERAL LIABILITY. The obligations and liabilities of Seller under this Agreement shall be joint and several obligations and liabilities of Lafayette Coal Company and Black Beauty Coal Company. 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 LAFAYETTE COAL COMPANY By: By: --------------------------- ---------------------------- Title: Title: --------------------------- ---------------------------- Date: Date: --------------------------- ---------------------------- BLACK BEAUTY COAL COMPANY By: ---------------------------- Title: ---------------------------- Date: ---------------------------- 30 EX-10.47 7 EXHIBIT 10.47 CONTRACT #95-361-026 COAL SUPPLY AGREEMENT THIS IS A COAL SUPPLY AGREEMENT (THE "AGREEMENT") DATED JANUARY 1, 1996 BETWEEN LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West Main Street, Louisville, Kentucky 40202 ("Buyer") and GREEN COAL COMPANY, INC., a Kentucky corporation, 6288 Chaney Road, Spottsville, Kentucky 42458-9719 ("Seller"). The parties hereto agree as follows: SECTION 1. GENERAL. Seller will sell to Buyer and Buyer will buy from Seller steam coal under all the terms and conditions of this Agreement. SECTION 2. TERMINATION OF CURRENT AGREEMENT; TERM. Section 2.1 CURRENT AGREEMENT. The Coal Supply Agreement dated November 1, 1994 between the parties shall be terminated effective December 31, 1995. Section 2.2 TERM. The term of this Agreement shall commence on January 1, 1996 and shall continue through December 31, 1998. SECTION 3. QUANTITY. Section 3.1 INITIAL NOMINATION. Within 15 days after this Agreement is executed by both parties, the Buyer will deliver to Seller the Buyer's nomination of the initial quantity of coal to be delivered hereunder. Such quantity shall be no less than 50,000 tons per month and no more than 125,000 tons per month. Section 3.2 CHANGES IN QUANTITY. At any time during the term of this Agreement, the Buyer shall have the right either to increase or decrease the quantity nominated hereunder CONTRACT #95-361-026 by up to 25% of the then current quantity. Buyer shall give notice of such change to Seller at least three months before the effective date of such change. Buyer may exercise this right repeatedly throughout the term of this Agreement, except that the quantity nominated may not be either increased or decreased more than 25% within any 90 day period and for any calendar year, the total quantity nominated by Buyer shall not be less than 600,000 tons and shall not be more than 2.5 million tons. Section 3.3 DELIVERY SCHEDULE. Seller shall deliver quantities of coal in accordance with Buyer's nominations hereunder. Time is of the essence with respect to Seller's deliveries; and failure by Seller to deliver in a timely manner shall constitute a material breach within the meaning of Section 16 of this Agreement. SECTION 4. SOURCE. Section 4.1 SOURCE. The coal sold hereunder, including coal purchased by Seller from third parties, shall be supplied from geological seam Kentucky #9, Henderson and Hatchett Mill Mines, Henderson County, Kentucky (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 have at the Coal Property adequate machinery, equipment and other facilities to produce, prepare and deliver coal in the quantity and of the quality required by this Agreement. Seller further agrees to operate and maintain such machinery, 2 CONTRACT #95-361-026 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 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, in the event that Seller is unable to produce or obtain coal from the Coal Property in the quantity and of the quality required by this Agreement, and such inability is not caused by a force majeure event as defined in Section 10, then Buyer will have the option of requiring that Seller supply substitute coal from other facilities and mines under all the terms and conditions of this Agreement including, but not limited to, the price provisions of Section 8, the quality specifications of Section 6.1, and the provisions of Section 5 concerning reimbursement to Buyer for increased transportation costs. Seller's delivery of coal not produced from the Coal 3 CONTRACT #95-361-026 Property without having received the express written consent of Buyer shall constitute a material breach of this Agreement. SECTION 5. DELIVERY. The coal shall be delivered to Buyer F.O.B. barge at the Green Coal dock at mile point 11.5 on the Green River (the "Delivery Point"). Seller may deliver the coal at a location different from the Delivery Point, provided, however, that Seller shall reimburse Buyer for any resulting increases in the cost of transporting the coal to Buyer's generating stations. Any resulting savings in such transportation costs shall be retained by Buyer. Title to and risk of loss 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 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 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 Delivery Point, including the demurrage, penalties for loading less than the specified minimum tonnage per barge, or 4 CONTRACT #95-361-026 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 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 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. SECTION 6. QUALITY. Section 6.1 SPECIFICATIONS. (a) The coal delivered hereunder shall conform to the following specifications on an "as received" basis: 5 CONTRACT #95-361-026
WASHED COAL Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) - ------------------------------------------------------------------------------------- BTU/LB. min. 11,000 LESS THAN 10,500 MOISTURE max. 12.3 lbs/MMBTU GREATER THAN 14.5 lbs/MMBTU ASH max. 9.6 lbs/MMBTU GREATER THAN 14.5 lbs/MMBTU SULFUR max. 2.6 lbs/MMBTU GREATER THAN 3.4 lbs/MMBTU SULFUR min. 1.8 lbs/MMBTU LESS THAN 1.8 lbs/MMBTU CHLORINE max. .1 lbs/MMBTU GREATER THAN .2 lbs/MMBTU FLUORINE max. .004 lbs/MMBTU GREATER THAN .01 lbs/MMBTU NITROGEN max. 1.3 lbs/MMBTU GREATER THAN 1.5 lbs/MMBTU ASH/SULFUR RATIO min. 5 LESS THAN 2.5 Size (3" x 0"): Top size (inches)* max. 3" x 0 " GREATER THAN 3" x 0" Fines (% by wgt) Passing 1/4" screen max. 45% GREATER THAN 50% % BY WEIGHT: VOLATILE max. 37 GREATER THAN 38 VOLATILE min. 34 LESS THAN 29 FIXED CARBON max. 46 GREATER THAN 48 FIXED CARBON min. 30 LESS THAN 30 GRINDABILITY (HGI) min. 55 LESS THAN 50 BASE ACID RATIO (B/A) max. .466 GREATER THAN .8 SLAGGING FACTOR** max. 1.5 GREATER THAN 2.0 FOULING FACTOR*** max. .32 GREATER THAN 1.0 ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) REDUCING ATMOSPHERE Initial Deformation min. 2000 min. 1900 Softening (H=W) min. 2050 min. 1975 Softening (H=1/2W) min. 2100 min. 2000 Fluid min. 2200 min. 2100 OXIDIZING ATMOSPHERE Initial Deformation min. 2400 min. 2200 Softening (H=W) min. 2400 min. 2280 Softening (H=1/2W) min. 2425 min. 2300 Fluid min. 2500 min. 2375
6 CONTRACT #95-361-026
BLEND COAL Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) - ------------------------------------------------------------------------------------- BTU/LB. min. 10,600 LESS THAN 10,000 MOISTURE max. 12.7 lbs/MMBTU GREATER THAN 14.5 lbs/MMBTU ASH max. 13.2 lbs/MMBTU GREATER THAN 15 lbs/MMBTU SULFUR max. 3.4 lbs/MMBTU GREATER THAN 3.5 lbs/MMBTU SULFUR min. 1.8 lbs/MMBTU LESS THAN 1.8 lbs/MMBTU CHLORINE max. .15 lbs/MMBTU GREATER THAN .2 lbs/MMBTU FLUORINE max. .006 lbs/MMBTU GREATER THAN .01 lbs/MMBTU NITROGEN max. 1.2 lbs/MMBTU GREATER THAN 1.5 lbs/MMBTU ASH/SULFUR RATIO min. 4.8 LESS THAN 2.5 Size (3" x 0"): Top size (inches)* max. 3" x 0" GREATER THAN 3" x 0" Fines (% by wgt) Passing 1/4" screen max. 45% GREATER THAN 50% % BY WEIGHT: VOLATILE max. 36 GREATER THAN 37 VOLATILE min. 30 LESS THAN 29 FIXED CARBON max. 44 GREATER THAN 46 FIXED CARBON min. 35 LESS THAN 30 GRINDABILITY (HGI) min. 55 LESS THAN 50 BASE ACID RATIO (B/A) max. .54 GREATER THAN .8 SLAGGING FACTOR** max. 1.9 GREATER THAN 2.0 FOULING FACTOR*** max. .4 GREATER THAN 1.0 ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857) REDUCING ATMOSPHERE Initial Deformation min. 1940 min. 1900 Softening (H=W) min. 2050 min. 1975 Softening (H=1/2W) min. 2100 min. 2000 Fluid min. 2200 min. 2100 OXIDIZING ATMOSPHERE Initial Deformation min. 2400 min. 2200 Softening (H=W) min. 2400 min. 2280 Softening (H=1/2W) min. 2425 min. 2300 Fluid min. 2500 min. 2375
7 CONTRACT #95-361-026
RAW COAL Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) - -------------------------------------------------------------------------------- BTU/LB. min. 10,300 LESS THAN 10,000 MOISTURE max. 13.4 lbs/MMBTU GREATER THAN 14.0 lbs/MMBTU ASH max. 14.25 lbs/MMBTU GREATER THAN 15.5 lbs/MMBTU SULFUR max. 4.0 lbs/MMBTU GREATER THAN 4.2 lbs/MMBTU SULFUR min. 1.8 lbs/MMBTU LESS THAN 1.8 lbs/MMBTU CHLORINE max. .15 lbs/MMBTU GREATER THAN .2 lbs/MMBTU FLUORINE max. .006 lbs/MMBTU GREATER THAN .01 lbs/MMBTU NITROGEN max. 1.2 lbs/MMBTU GREATER THAN 1.5 lbs/MMBTU ASH/SULFUR RATIO min. 4.8 LESS THAN 2.5 Size (3" x 0"): Top size (inches)* max. 3" x 0" GREATER THAN 3" x 0" Fines (% by wgt) Passing 1/4" screen max. 45% GREATER THAN 50% % BY WEIGHT: VOLATILE max. 36 GREATER THAN 37 VOLATILE min. 30 LESS THAN 29 FIXED CARBON max. 44 GREATER THAN 46 FIXED CARBON min. 35 LESS THAN 30 GRINDABILITY (HGI) min. 55 LESS THAN 50 BASE ACID RATIO (B/A) max. .54 GREATER THAN .8 SLAGGING FACTOR** max. 1.9 GREATER THAN 2.0 FOULING FACTOR*** max. .4 GREATER THAN 1.0 ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857) REDUCING ATMOSPHERE Initial Deformation min. 1940 min. 1900 Softening (H=W) min. 2050 min. 1975 Softening (H=1/2W) min. 2100 min. 2000 Fluid min. 2200 min. 2100 OXIDIZING ATMOSPHERE Initial Deformation min. 2400 min. 2200 Softening (H=W) min. 2400 min. 2280 Softening (H=1/2W) min. 2425 min. 2300 Fluid min. 2500 min. 2375
8 CONTRACT #95-361-026 * All the coal will be of such size that it will pass through a screen having circular perforations three (3) inches in diameter, but shall not contain more than forty-five per cent (45%) by weight of coal that will pass through a screen having circular perforations one-quarter (1/4) of an inch in diameter. ** Slagging Factor (R(s))=(B/A) x (Percent Sulfur by Weight(Dry)) *** Fouling Factor (R(f))=(B/A) x (Percent Na(2)0 by Weight(Dry)) The Base Acid Ratio (B/A) is herein defined as: BASE ACID RATIO (B/A) = (FE(2)0(3) + CA0 + MG0 + NA(2)0 + K(2)0) ------------------------------------------------ (Si0(2) + A1(2)0(3) + T10(2)) Note: As used herein GREATER THAN means greater than: LESS THAN means less than. (b) Seller shall deliver either all Blend Coal, all Raw Coal, or Washed Coal, Blend Coal and Raw Coal in any ratio Buyer desires hereunder at Buyer's option, subject to the pricing provision set forth in Section 8.1 and subject to the limitations that Washed Coal shall not constitute more than twenty percent (20%) of the total quantity to be delivered hereunder during any one month and Seller shall not be obligated to deliver more than 20,000 tons of Washed Coal in any one month. Buyer may change such nomination or such ratio at any time by giving Seller thirty days prior written notice of such change. Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall mean one barge load or a barge lot load in accordance with Buyer's sampling and analyzing practices. 9 CONTRACT #95-361-026 Section 6.3 REJECTION. Buyer has the right, but not the obligation, to reject any shipment which fail(s) to conform to the Rejection Limits set forth in Section 6.1 or contains extraneous materials. Buyer must reject such coal within seventy-two (72) hours of receipt of the coal analysis provided for in Section 7.2 or such right to reject is waived. In the event Buyer rejects such non-conforming coal, Buyer shall return the coal to Seller or, at Seller's request, divert such coal to Seller's designee, all at Seller's cost. Seller shall replace the rejected coal within five (5) working days from notice of rejection with coal conforming to the Rejection Limits set forth in Section 6.1. If Seller fails to replace the rejected coal within such five (5) working day period or the replacement coal is rightfully rejected, Buyer may purchase coal from another source in order to replace the rejected coal. Seller shall reimburse Buyer for (i) any amount by which the actual price plus transportation costs to Buyer of such coal purchased from another source exceed the price of such coal under this Agreement 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 10 CONTRACT #95-361-026 accepted by Buyer; however, the quantity Seller is obligated to sell to Buyer under the Agreement may or may not be reduced by the amount of each such non- conforming shipment at Buyer's sole option and the shipment shall nevertheless be considered "rejectable" under Section 6.4. 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 the coal sold hereunder fails to meet one or more of the Guaranteed Monthly Weighted Averages set forth in Section 6.1 for any two (2) months in a six (6) month period, or if nine (9) barge shipments in a 30 day period are rejectable by Buyer, Buyer may upon notice confirmed in writing and sent to Seller by certified mail, suspend future shipments except shipments already loaded into barges. Seller shall, within 10 days, provide Buyer with reasonable assurances that subsequent monthly deliveries of coal shall meet or exceed the Guaranteed Monthly Weighted Averages set forth in Section 6.1 and that the source will exceed 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 10 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. 11 CONTRACT #95-361-026 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 any of the Guaranteed Monthly Weighted Averages for any one (1) month within the next six (6) months or if three (3) barge shipments are rejectable within any one (1) month during such six (6) 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 method is mutually agreed upon by the parties. Such scales shall be duly reviewed 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 over or under the tolerance range allowable for the scale based on industry accepted standards, 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 industry- 12 CONTRACT #95-361-026 accepted standards. Samples for analyses shall be taken by any 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. Each sample taken by Buyer shall be divided into 4 parts and put into airtight containers, properly labeled and sealed. One part shall be used for analysis by Buyer; one part shall be used by Buyer as a check sample, if Buyer in its sole judgment determines it is necessary; one part shall be retained by Buyer until the 25th of the month following the month of unloading (the "Disposal Date") and shall be delivered to Seller for analysis if Seller so requests before the Disposal Date; and one part ("Referee Sample") shall be retained by Buyer until the Disposal Date. Seller shall be given copies of all analyses made by Buyer by the 12th day of the month following the month of unloading. Seller, on reasonable notice to Buyer shall have the right to have a representative present to observe the sampling and analyses performed by Buyer. Unless Seller requests a Referee Sample analysis before the Disposal Date, Buyer's analysis shall be used to determine the quality 13 CONTRACT #95-361-026 of the coal delivered hereunder. The Monthly Weighted Averages shall be determined by utilizing the individual shipment analyses. If any dispute arises before the Disposal Date, the Referee Sample retained by Buyer shall be submitted for analysis to an independent commercial testing laboratory ("Independent Lab") mutually chosen by Buyer and Seller. For each coal quality specification in question, a dispute shall be deemed not to exist and Buyer's analysis shall prevail and the analysis of the Independent Lab shall be disregarded if the analysis of the Independent Lab differs from the analysis of Buyer by an amount equal to or less than: (i) 0.50% moisture (ii) 0.50% ash on a dry basis (iii) 100 Btu/lb. on a dry basis (iv) 0.10% sulfur on a dry basis. For each coal quality specification in question, if the analysis of the Independent Lab differs from the analysis of Buyer by an amount more than the amounts listed above, then the analysis of the Independent Lab shall prevail and Buyer's analysis shall be disregarded. The cost of the analysis made by the Independent Lab shall be borne by Seller to the extent that Buyer's analysis prevails and by Buyer to the extent that the analysis of the Independent Lab prevails. SECTION 8. PRICE. Section 8.1 BASE PRICE. The base price ("Base Price") of the coal to be sold hereunder will be firm and will be determined by the type of coal nominated, the quantity nominated for 14 CONTRACT #95-361-026 the applicable calendar year, and the year for which the coal is nominated in accordance with the following matrix:
Raw Coal Blend Coal Washed Coal Tonnage Per -------- ---------- ----------- Year 1996 1997/98 1996 1997/98 1996 1997/98 ---- ---------------------------------------------------------- 600,000-1,200,000 .70000 .68000 .73000 .72000 .77000 .76000 1,200,000-1,800,000 .68000 .65000 .70000 .69000 .74000 .72000 GREATER THAN 1,800,000 .61750 .61250 .65000 .65400 .69000 .67000
(Note: all prices in c/MMBTU). For pricing purposes, the tonnage per year is based on tonnage nominated by Buyer in accordance with the terms of this Agreement and is not based on actual deliveries unless Buyer fails to accept delivery of coal tendered by Seller without legal excuse. For example, if Buyer duly nominates 1,300,000 tons, but Seller delivers only 1,100,000 tons for any reason other than Buyer's failure to accept delivery in breach hereof, then the pricing will be based on 1,300,000 tons. However, if Buyer duly nominates 1,300,000 tons, but Seller delivers only 1,100,000 tons because of Buyer's failure to accept delivery in breach hereof, the pricing will be based on 1,100,000 tons. Section 8.2 QUALITY PRICE DISCOUNTS. (a) The Base Price is based on coal meeting or exceeding the Guaranteed Monthly Weighted Average specifications as set forth in Section 6.1. Quality price discounts shall 15 CONTRACT #95-361-026 be applied for each specification each month to reflect failures to meet the Guaranteed Monthly Weighted Averages set forth in Section 6.1, as determined pursuant to Section 7.2, subject to the provisions set forth below. The discount values used are as follows: DISCOUNT VALUES $/MMBTU BTU/LB. 0.2604 $/LB./MMBTU SULFUR 0.1232 ASH 0.0083 MOISTURE 0.0016 (b) Notwithstanding the foregoing, for the BTU/LB specification each month, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. However, if the actual Monthly weighted Average fails to meet such applicable Discount Point, then the discount shall apply and shall be calculated on the basis of the difference between the actual Monthly Weighted Average AND THE GUARANTEED MONTHLY WEIGHTED AVERAGE pursuant to the methodology shown in Exhibit A attached hereto.
GUARANTEED MONTHLY WEIGHTED AVERAGE DISCOUNT POINT - ----------------------------------------------------------------------------- BTU/LB WASHED BLEND RAW WASHED BLEND RAW - ----------------------------------------------------------------------------- 11,000 10,600 10,300 10,800 10,400 10,100
16 CONTRACT #95-361-026 For example, if the actual Monthly Weighted Average of BTU/LB for Washed Coal equals 10,700, then the applicable discount would be [1-(10,700/11,000)] X $.2604 MMBTU = $.00710/MMBTU. Section 8.3 PAYMENT CALCULATION. Exhibit A attached hereto shows the methodology for calculating the coal payment and quality price discounts for the month Seller's coal was unloaded by Buyer. If there are any such discounts, Buyer shall apply credit to amounts owed Seller for the month the coal was unloaded. SECTION 9. INVOICES, BILLING AND PAYMENT. Section 9.1 INVOICING ADDRESS. Invoices will be sent to Buyer at the following address: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Director, Fuels Procurement and Delivery With a copy to: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Manager, Accounts Payable Section 9.2 INVOICE AND MONTHLY PAYMENT PROCEDURES. For all coal unloaded in any week (beginning Tuesday and ending Monday), Buyer shall make preliminary payment by wire transfer by the Tuesday immediately succeeding such week to National City Bank, Louisville, Kentucky, ABA #083000056, Account #704-3695-7, Attn: Mike Byers. 17 CONTRACT #95-361-026 Preliminary payment shall be in the amount of $12 per ton unloaded during the previous week. After the end of each calendar month, there will be a true-up as follows. The amount due for all coal (based on the initial Base Price minus any Quality Price Discounts) unloaded during any week (beginning Tuesday and ending Monday) which ended during such calendar month shall be calculated and compared to the sum of the preliminary payments made for coal unloaded during such weeks. The difference shall be paid by or paid to the Seller, as applicable, by the 25th of the following month or within ten (10) days after receipt of Seller's invoice, whichever is later. Section 9.3 TONNAGE ESTIMATES AND TRUE-UPS. Prior to the beginning of each calendar year, Buyer shall deliver to Seller Buyer's good faith estimate (the "Original Estimate") of whether the total tonnage to be nominated for such calendar year will be between 600,000 and 1,200,000 tons, between 1,200,000 tons and 1,800,000 tons, or greater than 1,800,000 tons. The Original Estimate and all revisions thereto shall be used only to determine the Base Price for initial monthly payment purposes and shall not limit any of Buyer's rights hereunder, including, but not limited to, Buyer's right to change the quantity as set forth in Section 3.2. After the end of each calendar quarter, Buyer promptly shall review its Original Estimate. If Buyer determines in good faith that the Original Estimate of annual quantity is incorrect, then Buyer promptly will deliver to Seller notice of a revision to the Original Estimate. With respect to invoicing and monthly payments which shall have occurred prior to such notice of revision, there will be a true-up as follows. If there shall have been 18 CONTRACT #95-361-026 an underpayment based on the revised estimate, Buyer shall pay to Seller the amount of the underpayment in a lump sum. If there shall have been an overpayment based on the revised estimate, then the Seller shall pay to the Buyer the amount of the overpayment in a lump sum. All invoicing and payments which occur after the notice of revision to the Original Estimate shall be based on the revised estimate. In any case, after the end of each calendar year, there will be a final true-up (if necessary) based on actual nominations under which the Buyer will pay to the Seller the amount of any underpayment in a lump sum and the Seller will pay to the Buyer the amount of any overpayment in a lump sum. Section 9.4 WITHHOLDING. Buyer shall have the right to withhold from payment of any billing or billings (i) any sums which it is not able in good faith to verify or which it otherwise in good faith disputes, (ii) any damages resulting from or likely to result from any breach of this Agreement by Seller, and (iii) any amounts owed to Buyer from Seller. Buyer shall notify Seller promptly in writing of any such issue, stating the basis of its claim and the amount it intends to withhold. Payment by Buyer, whether knowing or inadvertent, of any amount in dispute shall not be deemed a waiver of any claims or rights by Buyer with respect to any disputed amounts or payments made. SECTION 10. FORCE MAJEURE. 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 19 CONTRACT #95-361-026 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. 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. 20 CONTRACT #95-361-026 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 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 21 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 price per ton of coal, or in any other provision of this Agreement, an equitable adjustment shall be made in: 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. SECTION 12. NOTICES. Section 12.1 FORM AND PLACE OF NOTICE. Any official notice, request for approval or other document required to be given under this Agreement shall be in writing, unless otherwise provided herein, and shall be deemed to have been sufficiently given when delivered in person, transmitted by facsimile or other electronic media, delivered to an established mail service for same day or overnight delivery, or dispatched in the United States mail, postage 22 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.: Director, Fuels Procurement and Delivery with a copy to: Louisville Gas and Electric Company 820 West Broadway P.O. Box 32020 Louisville, Kentucky 40232 Attn.: Manager, Procurement Services If to Seller: Green Coal Company, Inc. 6288 Chaney Road Spottsville, Kentucky 42458-9719 Attn: Mike Exline 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. 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 of its rights and obligations under this Agreement as follows: The party desiring to exercise its right of early termination shall 23 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 quantity of coal (in tons) nominated under this Agreement during the calendar year immediately preceding the effective date of the early termination times the number of years remaining under this Agreement. For example, if Seller terminates this Agreement effective December 31, 1996 and the quantity of coal nominated under this Agreement during 1996 is 700,000 tons, then Seller would owe Buyer $4,900,000 under this Section 13. This provision is not intended to limit, liquidate, or otherwise affect in any manner damages recoverable for breach of this Agreement. SECTION 14. RIGHT TO RESELL. Buyer shall have the unqualified right to sell all or any of the coal purchased under this Agreement. 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 inside and outside attorney's fees) (i) relating to the barges provided by Buyer or Buyer's contractor while such barges are in the care and custody of the loading dock or loading facility, (ii) due to any failure of Seller to comply with laws, 24 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 carry insurance coverage with minimum limits as follows: (1) Commercial General Liability, including Completed Operations and Contractual Liability, $1,000,000 single limit liability. (2) Automobile General Liability, $1,000,000 single limit liability. (3) In addition, Seller shall carry excess liability insurance covering the foregoing perils in the amount of $4,000,000 for any one occurrence. (4) Workers' Compensation and Employer's Liability with statutory limits. If any of the above policies are written on a claims made basis, then the retroactive date of the policy or policies will be no later than the effective date of this Agreement. Certificates of Insurance satisfactory in form to the Buyer and signed by the Seller's insurer shall be supplied by the Seller to the Buyer evidencing that the above insurance is in force and that not less than 30 calendar days written notice will be given to the Buyer prior to any cancellation or material reduction in coverage under the policies. The Seller shall cause its insurer to waive all subrogation rights against the Buyer respecting all losses or claims arising from performance hereunder. Evidence of such waiver satisfactory in form and substance to the Buyer shall be exhibited in the Certificate of Insurance mentioned above. Seller's liability shall not be limited to its insurance coverage. 25 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. SECTION 18. DOCUMENTATION AND RIGHT OF AUDIT. Section 18.1 COAL RECORDS. Seller shall maintain all records and accounts pertaining to payments, quantities, quality analyses, and source for all coal supplied under this Agreement for a period lasting through the term of this Agreement and for two years 26 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 18.2 FINANCIAL INFORMATION. Within 30 days after the date completed, Seller shall deliver to Buyer copies of all of Seller's audited and unaudited financial statements (including, but not limited to, balance sheets, profit and loss statements, and cash flow statements) and supporting financing documents and records. 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). 27 SECTION 20. COAL PROPERTY INSPECTIONS. Buyer and its representatives, and others as may be required by applicable laws, ordinances and regulations shall have the right at all reasonable times and at their own expense to inspect the Coal Property, including the loading facilities, scales, sampling system(s), wash plant facilities, and mining equipment for conformance with this Agreement. Seller shall undertake reasonable care and precautions to prevent personal injuries to any representatives, agents or employees of Buyer (collectively, "Visitors") who inspect the Coal Property. Any such Visitors shall make every reasonable effort to comply with Seller's regulations and rules regarding conduct on the work site, made known to Visitors prior to entry, as well as safety measures mandated by state or federal rules, regulations and laws. Buyer understands that underground mines and related facilities are inherently high-risk environments. Buyer's failure to inspect the Coal Property or to object to defects therein at the time Buyer inspects the same shall not relieve Seller of any of its responsibilities nor be deemed to be a waiver of any of Buyer's rights hereunder. SECTION 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 or interpretation of this Agreement. 28 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 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; and further provided, however, that any assignment by Seller in connection with a sale of all or substantially all the assets of Seller shall trigger the provisions of Section 21. 29 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 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 GREEN COAL COMPANY, INC. By: By: ---------------------------- --------------------------------- Title: Title: ---------------------------- --------------------------------- Date: Date: ---------------------------- --------------------------------- 30 EX-10.48 8 EXHIBIT 10.48 COAL SUPPLY AGREEMENT THIS IS A COAL SUPPLY AGREEMENT (THE "AGREEMENT") DATED DECEMBER 15, 1995 BETWEEN LG&E POWER MARKETING INC., a California corporation, 220 West Main Street, Louisville, Kentucky 40202 ("Buyer") and W.B. COAL COMPANY, INC., an Ohio corporation, 155 East Broad Street, 23rd floor, Columbus, Ohio 43215, and WINDSOR COAL COMPANY, a West Virginia corporation, P.O. Box 39, West Liberty, West Virginia 26074 ("Producer" and collectively with W.B. Coal Company, Inc. the "Seller"). RECITALS A. The Buyer entered into a contract with Ohio Edison Company ("Ohio Edison") under which Buyer shall supply coal for the operation of Ohio Edison's Burger Plant located in Shady Side, Ohio, Ohio River Mile Point 102.3 and Ohio Edison's Mansfield Plant, located in Shippingsport, Pennsylvania, Ohio River Mile Point 33.2 (collectively the "Plant") and under which Ohio Edison will convert such coal to electric power and deliver such electric power to Buyer (the "Ohio Edison Agreement"). B. Buyer and Seller wish to enter into this Agreement to enable Buyer to fulfill all of its coal supply requirements under the Ohio Edison Agreement. AGREEMENTS The parties hereto agree as follows: SECTION 1. GENERAL. Seller will sell to Buyer and Buyer will buy from Seller steam coal under all the terms and conditions of this Agreement. SECTION 2. TERM. The term of this Agreement shall commence on the date this Agreement is fully executed and shall continue through December 31, 1996. 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 945,000 tons during the term hereof (the "Base Quantity"). Section 3.2 DELIVERY SCHEDULE. During the months of January through March, Seller shall deliver 75,000 tons per month; and during the months of April through December, Seller shall deliver 80,000 tons per month. Subject to Section 3.3 and the timely delivery of barges by Buyer or Buyer's barging contractor, 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 15 of this Agreement. As used in this Agreement, all references to a month shall mean a calendar month. Section 3.3 ADJUSTMENTS. Buyer shall have the right to change the monthly delivery schedule and the Base Quantity as follows. Upon thirty (30) days prior written notice to Seller, Buyer shall have the right to increase or decrease the Base Quantity (80,000 tons) for any months between April and December by up to 20,000 tons so that the minimum quantity for such months will be 60,000 tons and the maximum quantity for such months will be 100,000 tons. 2 SECTION 4. SOURCE. Section 4.1 SOURCE. The coal sold hereunder shall be supplied from geological seam Pittsburgh #8, Windsor Mine, Brooke County, West Virginia (the "Coal Property"). Section 4.2 ASSURANCE OF OPERATION AND RESERVES. Seller represents and warrants that the Coal Property contains coal of a quality and in quantities which will be sufficient to satisfy all the requirements of this Agreement. 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 balance of coal in the Coal Property to an amount less than that required to be supplied to Buyer hereunder. SECTION 5. DELIVERY. The coal shall be delivered to Buyer F.O.B. barge at the Windsor dock at mile point 78 on the Ohio River (the "Delivery Point"). Seller may deliver the coal at a location different from the Delivery Point, provided, however, that Seller shall reimburse Buyer for any resulting increases in the cost of transporting the coal to the Plant. 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 barges containing the coal are disengaged by Buyer's barging contractor from the loading dock, subject to Buyer's rejection rights set forth in Section 6.3. Buyer or its contractor shall furnish suitable open hopper barges in accordance with a mutually agreeable delivery schedule provided by Buyer to Seller. Seller shall arrange and pay for all costs of transporting the coal from the mines to the loading docks and loading and 3 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 reasonable penalties assessed by said barging contractor against 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 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 incidental water in the cargo boxes of the barges be pumped out as practicable 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 provide evidence thereof to Buyer in the form of a certificate of 4 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. SECTION 6. QUALITY. Section 6.1 SPECIFICATIONS. The coal delivered hereunder shall conform to the following specifications on an "as received" basis:
Rejection Limits Specifications Weighted Average (per shipment) - -------------------------------------------------------------------------------- BTU/LB. min. 12,200 LESS THAN 11,900 LBS/MMBTU: MOISTURE max. 8.0 GREATER THAN 8.5 ASH max. 9.5 GREATER THAN 9.8 SULFUR (Low Sulfur Months)* max. 3.00 GREATER THAN 3.80 SULFUR (High Sulfur Months)* max. 3.50 GREATER THAN 3.80 SULFUR min. 0.82 LESS THAN 0.82 Size (3" x 0"): max. 3X0 GREATER THAN 3X0 Top size (inches) Fines (% by wgt) Passing 1/4" screen max. 45 GREATER THAN 50** % BY WEIGHT: VOLATILE min. 37 LESS THAN 36 GRINDABILITY (HGI) min. 50 LESS THAN 50 (HGI) ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857)*** REDUCING ATMOSPHERE Initial Deformation min. 2040 min. 1950 Softening (H=W) min. 2090 min. 1980 Softening (H=1/2W) min. 2150 min. 2070 Fluid min. 2340 min. 2340
5 * "Low Sulfur Months" shall mean the months of January, February, and July through November; and "High Sulfur Months" shall mean the months of March through June and December. ** 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 fifty per cent (50%) by weight of coal that will pass through a screen having circular perforations one-quarter (1/4) of an inch in diameter. *** The Ash Fusion Temperature specifications shall apply only if Ohio Edison is experiencing an operational problem at the Plant related to ash fusion. Note: As used herein GREATER THAN means greater than: LESS THAN means less than. Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall mean one barge load or a barge lot load in accordance with Buyer's sampling and analyzing practices. Section 6.3 REJECTION. For each shipment, Seller will provide to Buyer approximate "as loaded" coal quality information for weight, moisture, ash, sulfur, and BTU/lb. by notice sent by telecopier to Buyer prior to the time the shipment arrives at the Plant. 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 6 Seller's receipt of notice of rejection with coal conforming to the Rejection Limits set forth in Section 6.1. If Seller fails to replace the rejected coal within such five (5) working day period or the replacement coal is rightfully rejected, Buyer may purchase coal of similar quality from another source in order to replace the rejected coal. Seller shall reimburse Buyer for (i) any amount by which the actual price plus transportation costs to Buyer of such coal purchased from another source exceed the price of such coal under this Agreement 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 as provided in Section 21.4. 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 foreign materials or excess moisture or fines which limit loading and/or handling ability, then such non- conforming coal shall be deemed accepted by Buyer; however, the quantity Seller is obligated to sell to Buyer under the Agreement may or may not be reduced by the amount of each such non-conforming shipment at Buyer's sole option and the shipment shall nevertheless be considered "rejectable" under Section 6.4. 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. 7 Section 6.4 SUSPENSION AND TERMINATION. If the coal sold hereunder fails to meet one or more of the Guaranteed Monthly Weighted Averages set forth in Section 6.1 for any two (2) months in a six (6) month period, or if nine (9) barge shipments in a month are rejectable by Buyer, Buyer may upon notice confirmed in writing and sent to Seller by certified mail, suspend future shipments except shipments already loaded into barges. Seller shall, within 10 business days of Seller's receipt of Buyer's written notice, provide Buyer with reasonable assurances that subsequent monthly deliveries of coal shall meet the Guaranteed Monthly Weighted Averages set forth in Section 6.1 and that the source will not exceed 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 10 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, again fails to meet any of the Guaranteed Monthly Weighted Averages for any one (1) month within the next six (6) months or if six (6) barge shipments are rejectable within any one (1) month during such six (6) 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 as provided in Section 21.4. 8 Section 6.5 WARRANTY DISCLAIMER. SELLER EXPRESSLY DENIES ANY IMPLIED WARRANTIES OR EXPRESS WARRANTIES EXCEPT AS SET FORTH HEREIN. SELLER DOES NOT WARRANT OR REPRESENT THAT THE COAL TO BE SOLD WILL BE FIT FOR ANY PARTICULAR PURPOSE. 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 Ohio Edison without expense to Seller on the basis of accurate scale weights at the Plant. Buyer shall exert commercially reasonable efforts to cause Ohio Edison to operate and maintain its scales in accordance with industry accepted standards and to allow Seller to be present and observe such weighing. In the event the scales are determined to be in error, an appropriate adjustment to price shall be made retroactively for a period of no more than 30 days. Section 7.2 SAMPLING AND ANALYSIS. The sampling and analysis of the coal delivered hereunder shall be performed by Ohio Edison and shall be accepted and used for the quality and characteristics of the coal delivered under this Agreement. All analyses shall be made in Ohio Edison's laboratory without expense to Seller in accordance with industry-accepted standards. If Seller should at any time question the correctness of either the sampling or the analyses made by Ohio Edison, Buyer shall exert commercially reasonable efforts to cause Ohio Edison to allow Seller to challenge the same by written notice. Thereafter, Buyer shall exert commercially reasonable efforts to cause Ohio Edison to allow Seller to have a representative observe the sampling and/or to receive a split of 9 the original laboratory sample taken. To meet this requirement, Buyer shall exert commercially reasonable efforts to cause Ohio Edison to retain the remaining portion of the sample for a period of forty-five (45) days after the sample is collected, so that Seller (and/or a mutually agreed upon commercial laboratory employed by Seller at Seller's cost) may obtain and analyze a portion of such sample. The results of such commercial testing laboratory's analysis shall be accepted as the quality and characteristics of such coal if the difference between Ohio Edison's results and such laboratory's results are beyond allowable ASTM tolerances. Section 7.3 REPORTING. Buyer shall either provide the results of Ohio Edison's weighing, sampling, and analysis of any coal delivered hereunder to Seller immediately upon Buyer's receipt of the same or have Ohio Edison provide such results to Seller at the same time Ohio Edison provides such results to Buyer. Buyer shall exert commercially reasonable efforts to cause the results of Ohio Edison's weighing, sampling, and analysis of the coal delivered hereunder to be delivered to Seller within ten (10) days after Ohio Edison's unloading of such coal. SECTION 8. PRICE. Section 8.1 BASE PRICE. The base price ("Base Price") of the coal to be sold hereunder will be firm and will be $.7730/MMBTU during the Low Sulfur Months (as defined in Section 6.1) and $.7040/MMBTU during the High Sulfur Months (as defined in Section 6.1). 10 Section 8.2 QUALITY PRICE DISCOUNTS. (a) The Base Price is based on coal meeting the Guaranteed Monthly Weighted Average specifications for ash, sulfur, and moisture and the Rejection Limits (per shipment) for BTU/lb as set forth in Section 6.1. Quality price discounts shall be applied for each specification each month and will be as follows: ASH: $0.75/ton for each full 1 lb./MMBTU in excess of 8.5 lb./MMBTU. SULFUR: $2.75/ton for each 1% or portion thereof in excess of 3% during the Low Sulfur Months and in excess of 3.7% during the High Sulfur Months, respectively. This discount will be applied on a proportionate basis. For example, if, during a Low Sulfur Month, actual sulfur is 3.2%, the price discount will be $0.55 per ton (.2x$2.75). MOISTURE: $0.25/ton for each full 1.00% in excess of 9.0% moisture. BTU/LB: $0.50/ton for each full 50 BTU/lb below 11,900 BTU/lb applied on a per shipment basis. If there are any such discounts, Buyer shall apply credit to amounts owed Seller for the month the coal was unloaded. SECTION 9. INVOICES, BILLING AND PAYMENT. Section 9.1 INVOICING ADDRESS. Invoices will be sent to Buyer at the following address: LG&E Power Marketing Inc. 12500 Fair Lakes Circle, Suite 350 Fairfax, Virginia 22033-3804 Attention: President 11 with a copy to: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Director, Fuels Procurement and Administration Section 9.2 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice Buyer at the Base Price, minus any quality price discounts, for all coal unloaded in a month by the fifteenth of the following month. Section 9.3 PAYMENT PROCEDURES FOR COAL SHIPMENTS. Payment for coal unloaded in a month shall be mailed by overnight mail 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 W.B. Coal Company, Inc., 155 East Broad Street, 23rd floor, Columbus, Ohio 43215. 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. 12 SECTION 10. FORCE MAJEURE. If either party hereto is delayed in or prevented from performing any of its obligations or from utilizing the coal sold under this Agreement due to acts of God, war, riots, civil insurrection, acts of the public enemy, strikes, lockouts, fires, floods, earthquakes, or mine roof falls, or due to force majeures declared by Ohio Edison which affect Ohio Edison's conversion of coal to electric power under the Ohio Edison Agreement, 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 such force majeure event Seller shall not reduce deliveries to Buyer and sell coal to any third party to whom it is not contractually obligated to sell coal at the time of 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. 13 Tonnage deficiencies resulting from a force majeure event shall be made up at Buyer's sole option on a mutually agreeable schedule. 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 the Plant. If any such changes makes necessary or appropriate an increase or decrease in the then current price per ton of coal, or in any other provision of this Agreement, an equitable adjustment shall be made in: 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. 14 SECTION 12. NOTICES. Section 12.1 FORM AND PLACE OF NOTICE. Unless otherwise specifically provided herein, 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: LG&E Power Marketing Inc. 12500 Fair Lakes Circle, Suite 350 Fairfax, Virginia 22033-3804 Attention: President With a copy to: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, Kentucky 40232 Attn.: Director, Fuels Procurement and Administration If to Seller: Windsor Coal Company c/o American Electric Power Service Corporation One Memorial Drive P.O. Box 700 Lancaster, Ohio 43130-0700 Attn.: Senior Vice President Fuel Supply AND W.B. Coal Company, Inc. 155 East Broad Street, 23rd floor Columbus, Ohio 43215 Attn: Wayne Boich 15 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. SECTION 13. RIGHT TO RESELL. Buyer shall have the unqualified right to sell all or any of the coal purchased under this Agreement to any third party and for purposes other than the operation of the Plant. SECTION 14. INDEMNITY AND INSURANCE. Section 14.1 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, or legal actions for personal injuries, property damage and pollution (including reasonable inside and outside attorney's fees) relating to the barges provided by Buyer or Buyer's contractor while such barges are in the care and custody of the loading dock or loading facility. Section 14.2 INSURANCE. Seller agrees to carry insurance coverage or self-insurance 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. 16 (4) Workers' Compensation and Employer's Liability with statutory limits. If any of the above policies are written on a claims made basis, then the retroactive date of the policy or policies will be no later than the effective date of this Agreement. Certificates of Insurance satisfactory in form to the Buyer and signed by the Seller's insurer shall be supplied by the Seller to the Buyer evidencing that the above insurance is in force and that not less than 30 calendar days written notice will be given to the Buyer prior to any cancellation or material reduction in coverage under the policies. The Seller shall cause its insurer to waive all subrogation rights against the Buyer respecting all losses or claims arising from performance hereunder. Evidence of such waiver satisfactory in form and substance to the Buyer shall be exhibited in the Certificate of Insurance mentioned above. Seller's liability shall not be limited to its insurance coverage. SECTION 15. 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 17 period in addition to all the other rights and remedies available to the aggrieved party under this Agreement and at law and in equity, as provided in Section 21.4. SECTION 16. 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 sale of Seller's coal to Buyer hereunder. SECTION 17. DOCUMENTATION AND RIGHT OF AUDIT. Seller and Buyer shall maintain all records and accounts pertaining to payments, quantities, quality analyses, and source for all coal supplied under this Agreement for a period lasting through the term of this Agreement and for two years thereafter. Seller and Buyer shall have the right at no additional expense to the other party 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 18. COAL PROPERTY VISITS. Buyer and its representatives, and others as may be required by applicable laws, ordinances and regulations shall have the right at all reasonable times and at their own expense to visit the Coal Property, including the loading facilities, scales, sampling system(s), wash plant facilities, and mining equipment for conformance with this Agreement. Seller shall undertake reasonable care and precautions to prevent personal injuries to any representatives, agents or employees of Buyer (collectively, "Visitors") who visit the Coal Property. Any such Visitors shall make every reasonable effort to comply with Seller's regulations and rules regarding conduct on 18 the work site, made known to Visitors prior to entry, as well as safety measures mandated by state or federal rules, regulations and laws. Buyer understands that underground mines and related facilities are inherently high-risk environments. Buyer's failure to visit the Coal Property shall not relieve Seller of any of its responsibilities nor be deemed to be a waiver of any of Buyer's rights hereunder. SECTION 19. JOINT AND SEVERAL LIABILITY. The obligations and liabilities of Seller under this Agreement shall be the joint and several obligations and liabilities of W.B. Coal Company, Inc. and Windsor Coal Company. SECTION 20. CONFIDENTIALITY AND PUBLICITY. Except as required by law or government regulation, the existence and the provisions of this Agreement shall be held in confidence by Seller and Buyer and shall not be disclosed by Seller or Buyer (or any affiliates of Seller or Buyer) to any third party except as authorized in writing by the other party. Neither party (including its affiliates) shall issue news releases, generate publicity, or otherwise make statements to the media concerning the existence or provisions of this Agreement without first obtaining the written approval 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. 19 Section 21.2 HEADINGS. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning or 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. In the event of a breach of this Agreement, the aggrieved party shall have all the remedies specifically provided in this Agreement in addition to all other remedies provided by law or in equity. However, in no event shall either party be liable to the other party for any special, indirect, or consequential damages, subject to Section 14.1. 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 20 company, controlling, controlled by, or under common control with Buyer. However such assignment shall not relieve Buyer of its obligations under the Agreement. 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 hereto. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed as of the date first above written. LG&E POWER MARKETING INC. W.B. COAL COMPANY, INC. By: By: ---------------------------- --------------------------------- Title: Title: ---------------------------- --------------------------------- Date: Date: ---------------------------- --------------------------------- WINDSOR COAL COMPANY By: ---------------------------- Title: ---------------------------- Date: ---------------------------- 21 EX-10.49 9 EXHIBIT 10.49 CONTRACT NO.: 96-063-026 COAL SUPPLY AGREEMENT This is a coal supply agreement (the "Agreement") dated January 1, 1996 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"). AGREEMENTS The parties hereto agree as follows: SECTION 1. GENERAL Section 1.1 TERMINATION OF CURRENT AGREEMENT. The Coal Supply Agreement dated January 1, 1994 between Seller and Buyer is hereby terminated as of December 31, 1995. Such current agreement shall apply to coal delivered by December 31, 1995. Section 1.2 NEW AGREEMENT. Effective January 1, 1996, Seller will sell to Buyer and Buyer will buy from Seller, steam coal under all the terms and conditions of this Agreement. This Agreement shall apply to coal delivered on January 1, 1996 and thereafter. SECTION 2. TERM Subject to Section 8.2, the term of this Agreement shall commence on the effective date set forth in Section 1.2 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. CONTRACT NO.: 96-063-026 SECTION 3. QUANTITY Section 3.1 ANNUAL QUANTITY. Seller shall sell and deliver and Buyer shall purchase and accept delivery of the following annual quantity of coal ("Annual Quantity"):
YEAR ANNUAL QUANTITY (TONS) ------ ------------------------ 1996 1,000,000 1997 1,000,000 1998 1,000,000 1999 1,000,000
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 a reasonable schedule which shows 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 17 of this Agreement. This Section 3.2 applies to 1996 deliveries which occur after the execution of this Agreement except that Buyer shall have until ten (10) business days after this Agreement becomes fully executed to so specify such monthly delivery schedule for 1996. Section 3.3 ADJUSTMENTS. 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, subject to Seller's written consent which shall not be unreasonably 2 CONTRACT NO.: 96-063-026 withheld or delayed. However, the total quantity for each calendar year shall be as set forth in Section 3.1. SECTION 4. SOURCE Section 4.1 SOURCE. Subject to Section 4.4 hereof, the coal sold hereunder shall be supplied from Peabody Coal Company's Lynnville Mine, #5, #6, and #7 seams, Warrick and Spencer Counties, Indiana (the "Coal Property"). Section 4.2 ASSURANCE OF OPERATION AND RESERVES. Seller represents and warrants that the Coal Property contains economically recoverable coal of a quality and in quantities which will be sufficient to satisfy all the requirements of this Agreement. Seller agrees and warrants that it will cause to have at the Coal Property adequate machinery, equipment and other facilities to produce, 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 3 CONTRACT NO.: 96-063-026 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, in the event that Seller is unable to produce or obtain coal from the Coal Property in the quantity and of the quality required by this Agreement, and such inability is not caused by a force majeure event as defined in Section 11, then Buyer will have the right to require that Seller supply substitute coal from other facilities and mines. Seller shall also have the right to supply substitute coal after having received Buyer's prior written consent (which shall not be unreasononably withheld). Such substitute coal shall be provided under all the terms and conditions of this Agreement including, but not limited to, the price provisions of Section 8, the quality specifications of Section 6.1, and the provisions of Section 5 concerning reimbursement to Buyer for increased transportation costs. Seller's delivery of coal not produced from the Coal Property without having received the express written consent of Buyer shall constitute a material breach of this Agreement. SECTION 5. DELIVERY 5.1 RAIL DELIVERY. Subject to Section 9, the coal shall be delivered to Buyer F.O.B. railcar at the Lynnville or Squaw Creek rail loading facility near Boonville, Indiana (the "Delivery Point"). Seller may deliver the coal at a location different from the Delivery Point, provided, however, that Seller shall reimburse Buyer for any resulting increases in the cost of transporting the coal to Buyer's generating stations. Any resulting savings in such transportation costs shall be shared equally by Buyer and Seller. 4 CONTRACT NO.: 96-063-026 Title to and risk of loss respecting coal will pass to Buyer and the coal will be considered to be delivered when it is loaded into the railcars at the rail loading facility. Buyer or its contractor shall furnish suitable railcars in accordance with a delivery schedule provided by Buyer to Seller. Seller shall be responsible for and pay the cost of repairs for any damages caused by Seller to railcars owned or leased by Buyer while such railcars are in Seller's control or custody. Seller shall comply with the applicable provisions of Buyer's rail contractor's tariff. Section 5.2 FREEZE CONDITIONING. At Buyer's request, Seller shall treat (or have treated) any shipment of coal hereunder with a freeze conditioning agent approved by Buyer in order to maintain coal handling characteristics during shipment. If requested by Buyer, Seller shall also treat (or have treated) any railcars specified by Buyer with a side release agent approved by Buyer. The price for each such requested chemical treatment shall be an amount equal to Seller's cost of materials and applications calculated on a per gallon basis for each application of freeze conditioning agent and/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. Section 5.3 BARGE DELIVERY. At any time during the term of this Agreement, Buyer shall have the right to change the delivery term from F.O.B. railcar to F.O.B. barge by giving Seller ninety (90) days advance written notice of such change. If the Buyer so exercises its right to change to barge deliveries, then the following provisions shall apply: 5 CONTRACT NO.: 96-063-026 (a) The Base Price shall be equivalent to the Base Price set forth in Section 8.1, except that the Base Price for barge deliveries shall be increased to reflect the difference in Seller's costs to transport coal from the mine to the Barge Delivery Point (as defined below) and load it into barges and the Seller's costs to transport coal from the mine to the rail Delivery Point and load it into railcars. (b) The coal shall be delivered to Buyer F.O.B. barge at whatever dock is then available and will result in the lowest delivered cost of coal to Buyer hereunder (the "Barge Delivery Point"). Title to 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 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 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 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 6 CONTRACT NO.: 96-063-026 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 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. (c) All other provisions of this Agreement shall remain in full force and effect. 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: 7 CONTRACT NO.: 96-063-026
Guaranteed Monthly Rejection Limits Specifications Weighted Average (per shipment) - -------------------------------------------------------------------------------- BTU/LB. min. 10,950 LESS THAN 10,750 MOISTURE max. 12.91 lbs/MMBTU GREATER THAN 14.00 ASH max. 8.00 lbs/MMBTU GREATER THAN 9.50 SULFUR max. 2.95 lbs/MMBTU GREATER THAN 3.30 SULFUR min. 1.80 lbs/MMBTU LESS THAN 1.80 CHLORINE max. 0.07 lbs/MMBTU GREATER THAN 0.08 FLUORINE max. 0.013 lbs/MMBTU GREATER THAN 0.013 NITROGEN max. 1.50 lbs/MMBTU GREATER THAN 1.60 ASH/SULFUR RATIO min. 2.5:1 LESS THAN 2.5:1 Size (3" x 0"): Top size (inches) max. 3"x0" GREATER THAN 3"x0" Fines (% by wgt) Passing 1/4" screen max. 40% GREATER THAN 45% % BY WEIGHT: VOLATILE max. 34.5 GREATER THAN 35.0 VOLATILE min. 33.5 LESS THAN 33.0 FIXED CARBON max. 44 GREATER THAN 45 FIXED CARBON min. 40 LESS THAN 40 GRINDABILITY (HGI) min. 53 LESS THAN 50 BASE ACID RATIO (B/A) SLAGGING FACTOR* max. 2.0 GREATER THAN 2.0 FOULING FACTOR** max. 0.5 GREATER THAN 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
8 CONTRACT NO.: 96-063-026 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 The Base Acid Ratio (B/A) is herein defined as: BASE ACID RATIO (B/A) = (Fe(2)0(3) + Ca0 + Mg0 + Na(2)0 + K(2)0) ------------------------------------------------ (Si0(2) + A1(2)0(3) + T10(2)) Note: As used herein GREATER THAN means greater than: LESS THAN means less than. Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall mean one barge load or a barge lot load, or one unit trainload, in accordance with Buyer's sampling and analyzing practices. Section 6.3 REJECTION. Buyer has the right, but not the obligation, to reject any shipment which fail(s) to conform to the Rejection Limits set forth in Section 6.1 or contains extraneous materials. Buyer must reject such coal within seventy-two (72) hours of receipt of the coal analysis provided for in Section 7.2 or such right to reject is waived. In the event Buyer rejects such non-conforming coal, Buyer shall return the coal to Seller or, at Seller's request, divert such coal to Seller's designee, all at Seller's cost. Seller shall replace the rejected coal within five (5) working days from notice of rejection with coal conforming to the Rejection Limits set forth in Section 6.1. If Seller fails to replace the rejected coal within such five (5) working day period or the replacement coal is rightfully rejected, Buyer may purchase coal from another source in order to replace the rejected coal. Seller shall reimburse Buyer for (i) any amount by which the actual 9 CONTRACT NO.: 96-063-026 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 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 10 CONTRACT NO.: 96-063-026 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 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 11 CONTRACT NO.: 96-063-026 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. Each sample taken by Buyer shall be divided into 4 parts and put into airtight containers, properly labeled and sealed. One part shall be used for analysis by Buyer; one part shall be used by Buyer as a check sample, if Buyer in its sole judgment determines it is necessary; one part shall be retained by Buyer until the 25th of the month following the month of unloading (the 12 CONTRACT NO.: 96-063-026 "Disposal Date") and shall be delivered to Seller for analysis if Seller so requests before the Disposal Date; and one part ("Referee Sample") shall be retained by Buyer until the Disposal Date. Seller shall be given copies of all analyses made by Buyer by the 12th day of the month following the month of unloading. Seller, on reasonable notice to Buyer shall have the right to have a representative present to observe the sampling and analyses performed by Buyer. Unless Seller requests a Referee Sample analysis before the Disposal Date, Buyer's analysis shall be used to determine the quality of the coal delivered hereunder. The Monthly Weighted Averages shall be determined by utilizing the individual shipment analyses. If any dispute arises before the Disposal Date, the Referee Sample retained by Buyer shall be submitted for analysis to an independent commercial testing laboratory ("Independent Lab") mutually chosen by Buyer and Seller. For each coal quality specification in question, a dispute shall be deemed not to exist and Buyer's analysis shall prevail and the analysis of the Independent Lab shall be disregarded if the analysis of the Independent Lab differs from the analysis of Buyer by an amount equal to or less than: (i) 0.50% moisture (ii) 0.50% ash on a dry basis (iii) 100 Btu/lb. on a dry basis (iv) 0.10% sulfur on a dry basis. For each coal quality specification in question, if the analysis of the Independent Lab differs from the analysis of Buyer by an amount more than the amounts listed above, then the analysis of the Independent Lab shall prevail and Buyer's analysis shall be disregarded. The cost 13 CONTRACT NO.: 96-063-026 of the analysis made by the Independent Lab shall be borne by Seller to the extent that Buyer's analysis prevails and by Buyer to the extent that the analysis of the Independent Lab prevails. SECTION 8. PRICE Section 8.1 PRICE. Subject to Section 9 and Section 8.2, the base price (the "Base Price") of the coal to be sold hereunder will be firm and will be $.78767/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 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 and Section 5. 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, 1998. The party requesting such a review shall give written notice of its request to the other party on or before October 1, 1997. 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, 1997 without liability due to such termination for either party. 14 CONTRACT NO.: 96-063-026 Section 8.3 QUALITY PRICE DISCOUNTS. (a) The Base Price is based on coal meeting or exceeding the Guaranteed Monthly Weighted Average specifications as set forth in Section 6.1. Quality price discounts shall be applied for each specification each month to reflect failures to meet the Guaranteed Monthly Weighted Averages set forth in Section 6.1, as determined pursuant to Section 7.2, subject to the provisions set forth below. The discount values used are as follows: DISCOUNT VALUES $/MMBTU BTU/LB. 0.2604 $/LB./MMBTU SULFUR 0.1232 ASH 0.0083 MOISTURE 0.0016 (b) Notwithstanding the foregoing, for each specification each month, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. However, if the actual Monthly Weighted Average fails to meet such applicable Discount Point, then the discount shall apply and shall be calculated on the basis of the difference between the actual Monthly Weighted Average AND THE GUARANTEED MONTHLY WEIGHTED AVERAGE pursuant to the methodology shown in Exhibit A attached hereto. 15 CONTRACT NO.: 96-063-026
Guaranteed Monthly Weighted Average Discount Point ---------------- -------------- BTU/LB min. 10,950 10,750 LB/MMBTU: SULFUR max. 2.95 3.30 ASH max. 8.00 9.50 MOISTURE max. 12.91 14.00
For example, if the actual Monthly Weighted Average of sulfur equals 3.35 lb/MMBTU, then the applicable discount would be (3.35 lb. - 2.95 lb.) X $.1232/lb/MMBTU = $.04928/MMBTU. Section 8.4 PAYMENT CALCULATION. Exhibit A 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. SPECIAL PRICE AND DELIVERY PROVISIONS. Section 9.1 JAN. 1 - FEB. 4, 1996. Notwithstanding any other provision in this Agreement, the following provisions shall apply for all coal delivered by Seller between January 1, 1996 and February 4, 1996: (a) The coal will be delivered to Buyer F.O.B. barge at the Yankeetown Dock at Mile Point 772.5 on the Ohio River (the "Yankeetown Dock"). (b) The Base Price will be $.78767/MMBTU plus the costs actually incurred by the Seller to transport coal from the Coal Property to the Yankeetown Dock and load such coal 16 CONTRACT NO.: 96-063-026 onto barges. Such costs shall be calculated on a per ton basis and shall in no event exceed $2.60 per ton. (c) Except as specifically set forth in (a) and (b) above, all the provisions of this Agreement shall apply. Section 9.2 FEB. 5 - FEB. 12, 1996. Notwithstanding any other provision in this Agreement, the following provision shall apply for all coal delivered F.O.B. barge by Seller between February 5, 1996 and February 12, 1996: (a) The coal will be delivered to Buyer F.O.B. barge at the Yankeetown Dock. (b) The Base Price will be $.78767/MMBTU plus $1.80 per ton. (c) Except as specifically set forth in (a) and (b) above, all of the provisions of this Agreement shall apply. SECTION 10. INVOICES, BILLING AND PAYMENT. Section 10.1 INVOICING ADDRESS. Invoices will be sent to LG&E at the following address: Louisville Gas and Electric Company 220 West Main Street P.O. Box 32010 Louisville, KY 40232 Attention: Director, Fuels Procurement and Delivery With a copy to: Louisville Gas and Electric Company 820 West Broadway P. O. Box 32020 Louisville, KY 40232 Attention: Manager, Accounts Payable 17 CONTRACT NO.: 96-063-026 Section 10.2 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 10.3 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 63150-3099. To make wire transfers contact Boatman's Bank, Account ABA 081000032, wire transfer account 100101223441. Section 10.4 WITHHOLDING. Buyer shall have the right to withhold from payment of any billing or billings (i) any sums which it is not able in good faith to verify or which it otherwise in good faith disputes, (ii) any damages resulting from or likely to result from any breach of this Agreement by Seller, and (iii) any amounts owed to Buyer from Seller. Buyer shall notify Seller promptly in writing of any such issue, stating the basis of its claim and the amount it intends to withhold. Payment by Buyer, whether knowing or inadvertent, of any amount in dispute shall not be deemed a waiver of any claims or rights by Buyer with respect to any disputed amounts or payments made. SECTION 11. FORCE MAJEURE Section 11.1 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 18 CONTRACT NO.: 96-063-026 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 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. 19 CONTRACT NO.: 96-063-026 Tonnage deficiencies resulting from a force majeure event shall be made up at Buyer's sole option on a reasonable schedule. Section 11.2 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 without further obligation hereunder on the part of either party. SECTION 12. CHANGES. Buyer may, by mutual agreement with Seller, at any time by written notice pursuant to Section 13 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 20 CONTRACT NO.: 96-063-026 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 make 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 12 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 12, then this Agreement shall continue in full force and effect without taking into account such requested changes. SECTION 13. NOTICES Section 13. 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 21 CONTRACT NO.: 96-063-026 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: Director, Fuels Procurement and Delivery with a copy to: Louisville Gas and Electric Company 820 West Broadway P.O. Box 32020 Louisville, Kentucky 40232 Attn: Manager, Procurement Services If to Seller: Peabody COALSALES Company 1951 Barrett Court Suite 200 P.O. Box 1996 Henderson, Kentucky 42420-1996 Attn: Vice-President, Sales Section 13.2 CHANGE OF PERSON OR ADDRESS. Either party may change the person or address specified above upon giving written notice to the other party of such change. Section 13.3 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 14. 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 22 CONTRACT NO.: 96-063-026 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 Annual 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, 1998) or the termination of this Agreement (i.e., January 1, 2000), as applicable. For example, if Seller terminates this Agreement effective January 1, 1997, then Seller would owe Buyer $3,500,000 under this Section 14. SECTION 15. RIGHT TO RESELL. Buyer shall have the unqualified right to sell all or any of the coal purchased under this Agreement. SECTION 16. INDEMNITY AND INSURANCE Section 16.1 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 16.2 INSURANCE. Seller agrees to maintain insurance coverage with minimum limits as follows: 23 CONTRACT NO.: 96-063-026 (1) Commercial General Liability, including Completed Operations and Contractual Liability, $1,000,000 single limit liability. (2) Automobile General Liability, $1,000,000 single limit liability. (3) In addition, Seller shall carry excess liability insurance covering the foregoing perils in the amount of $4,000,000 for any one occurrence. (4) Workers' Compensation and Employer's Liability with statutory limits. If any of the above policies are written on a claims made basis, then the retroactive date of the policy or policies will be no later than the effective date of this Agreement. Certificates of Insurance satisfactory in form to the Buyer and signed by the Seller's insurer shall be supplied by the Seller to the Buyer evidencing that the above insurance is in force and that not less than 30 calendar days written notice will be given to the Buyer prior to any cancellation or material reduction in coverage under the policies. The Seller shall cause its insurer to waive all subrogation rights against the Buyer respecting all losses or claims arising from performance hereunder. Evidence of such waiver satisfactory in form and substance to the Buyer shall be exhibited in the Certificate of Insurance mentioned above. Seller's liability shall not be limited to its insurance coverage. SECTION 17. 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 24 CONTRACT NO.: 96-063-026 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 18. TAXES, DUTIES AND FEES Seller shall pay when due, and the price set forth in Section 8 of this Agreement shall be inclusive of, all taxes, duties, fees and other assessments of whatever nature imposed by governmental authorities with respect to the transactions contemplated under this Agreement. SECTION 19. 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 20. 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 CFR 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 25 CONTRACT NO.: 96-063-026 in 41 CFR 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 CFR 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 21. COAL PROPERTY INSPECTIONS AND INJURIES TO REPRESENTATIVES Buyer and its representatives, and others as may be required by applicable laws, ordinances and regulations shall have the right at all reasonable times and at their own expense to inspect the Coal Property, including the loading facilities, scales, sampling system(s), wash plant facilities, and mining equipment for conformance with this Agreement. Seller shall undertake reasonable care and precautions to prevent personal injuries to any representatives, agents or employees of Buyer (collectively, "Visitors") who inspect the Coal Property. Any such Visitors shall make every reasonable effort to comply with Seller's regulations and rules regarding conduct on the work site, made known to Visitors prior to entry, as well as safety measures mandated by state or federal rules, regulations and laws. Buyer understands that mines and related facilities are inherently high-risk environments. Buyer's failure to inspect the Coal Property or to object to defects therein at the time Buyer inspects the same shall not relieve Seller of any of its responsibilities nor be deemed to be a waiver of any of Buyer's rights hereunder. 26 CONTRACT NO.: 96-063-026 SECTION 22. MISCELLANEOUS Section 22.1 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 22.2 HEADINGS. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning of interpretation of this Agreement. Section 22.3 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 22.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement shall be cumulative and in addition to other remedies provided under this Agreement or by law or in equity. Section 22.5 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. 27 CONTRACT NO.: 96-063-026 Section 22.6 BINDING EFFECT. This Agreement shall bind and inure to the benefit of the parties and their successors and assigns. Section 22.7 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 22.8 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 22.9 AMENDMENTS. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by both parties hereto. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed as of the date first above written. LOUISVILLE GAS AND ELECTRIC PEABODY COALSALES COMPANY COMPANY By: /s/ Christopher Hermann By: /s/ illegible ---------------------------------- ----------------------------------- Chris Hermann Vice President and General Manager Title: Vice President Sales & Marketing Wholesale Electric Business -------------------------------- Date: 2/22/96 Date: 2/21/96 ---------------------------------- --------------------------------
28 EX-10.49A 10 EXHIBIT 10.49A Page 1 of 2 EXHIBIT A SAMPLE COAL PAYMENT CALCULATIONS Total Evaluated Coal Costs for Contract No. - -------------------------------------------------------------------------------- For contracts supplied from multiple "origins", each "origin" will be calculated individually.
SECTION I BASE DATA - ------------------------------------------------------------ 1) Base F.O.B. price per ton: $_17.25_ /ton 1a) Tons of coal delivered: ________ tons 2) Guaranteed average heat content: __10,950_ B.T.U./LB. 2r) As received monthly avg. heat content: ________ B.T.U./LB. 2a) Energy delivered in M.M.B.T.U.: ________ MMBTU [(Line 1a) *2,000 lb./ton *(Line 2r)] *MMBTU/1,000,000 BTU [( ) *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 _2.95____ LBS./MMBTU 3r) As received monthly avg. sulfur _________ LBS./MMBTU 4) Guaranteed monthly avg. max ash _8.00____ LBS./MMBTU 4r) As received monthly avg. ash _________ LBS./MMBTU 5) Guaranteed monthly avg. max moisture _12.91___ LBS./MMBTU 5r) As received monthly avg. moisture _________ LBS./MMBTU
SECTION II DISCOUNTS - ------------------------------------------------------------ Assign a (-) to all discounts (round to five (5) decimal places) 6d) B.T.U./LB.: If line 2r is less than 10,750 BTU/lb. {1-[(line 2r)/(line 2)]} *$0.2604/MMBTU {1-[( )/( )]} *$0.2604 = $________ /MMBTU 7d) SULFUR: If line 3r is greater than 3.3 lbs./MMBTU [(line 3r)-(line 3)] *$0.1232/lb sulfur [( )-( )] *$0.1232 = $________ /MMBTU 8d) ASH: If line 4r is greater than 9.50 lbs./MMBTU [(line 4r)-(line 4)] *$0.0083/lb ash [( )-( )] $0.0083 = $________ /MMBTU 9d) MOISTURE: If line 5r is greater than 14.00 lbs./MMBTU [(line 5r)-(line 5)] *$0.00 16/lb moisture [( )-( )] *$0.0016 = $________ /MMBTU
Exhibit A Page 2 of 2
SECTION III TOTAL PRICE ADJUSTMENTS - ------------------------------------------------------------ Determine total Discounts as follows: Assign a (-) to all Discounts and enter number for: Line 6d: $________ /MMBTU Line 7d: $________ /MMBTU Line 8d: $________ /MMBTU Line 9d: $________ /MMBTU 10) Total Discounts (-): Algebraic sum of above: $________ /MMBTU 11) Total evaluated coal price = (line 2b) + (line 10) $________ /MMBTU + $________ /MMBTU = $________/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-12 11 EXHIBIT 12 EXHIBIT 12 LOUISVILLE GAS AND ELECTRIC COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Thousands of $)
1995 1994 1993 1992 1991 ---- ---- ---- ---- ---- Earnings: Income before cumulative effect of a change in accounting principle per statements of income.......................................... $ 83,184 $ 61,689 $ 90,535 $ 73,793 $ 94,643 Add: Federal income taxes - current....................... 35,824 30,926 42,091 13,785 35,490 State income taxes - current......................... 8,795 7,726 12,954 3,140 8,425 Deferred Federal income taxes - net.................. 4,261 (950) 4,712 20,441 17,207 Deferred State income taxes - net.................... 2,788 956 226 8,470 6,085 Investment tax credit - net.......................... (4,742) (4,619) (7,821) (5,033) (11,472) Fixed charges........................................ 43,550 44,665 49,640 52,196 55,171 -------- -------- -------- -------- -------- Earnings........................................... 173,660 140,393 192,337 166,792 205,549 -------- -------- -------- -------- -------- Fixed Charges: Interest Charges per statements of income............ 41,918 42,856 47,496 49,833 52,680 Add: Interest income (1)................................ - - - 4 98 One-third of rentals charged to operating expense (2).............................. 1,632 1,809 2,144 2,359 2,393 -------- -------- -------- -------- -------- Fixed charges.................................... $ 43,550 $ 44,665 $ 49,640 $ 52,196 $ 55,171 -------- -------- -------- -------- -------- Ratio of Earnings to Fixed Charges..................... 3.99 3.14 3.87 3.20 3.73 -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
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. -68- EX-23 12 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, 1996, included in this Form 10-K, into the Company's previously filed Registration Statement No. 33-13427. Louisville, Kentucky Arthur Andersen LLP March 27, 1996 - 69 - EX-24 13 EXHIBIT 24 POWER OF ATTORNEY 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, 1995 (the 1995 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 WALTER Z. BERGER, 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 1995 Form 10-K and to any and all amendments to such 1995 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 6th day of March 1996. 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 Anne H. McNamara - ----------------------------------- --------------------------------------- Owsley Brown II, Director Anne H. McNamara, Director S. Gordon Dabney T. Ballard Morton, Jr. - ----------------------------------- --------------------------------------- S. Gordon Dabney, Director T. Ballard Morton, Jr., Director Walter Z. Berger Dr. Donald C. Swain - ----------------------------------- --------------------------------------- Walter Z. Berger, Principal Dr. Donald C. Swain, Director Financial and Accounting Officer Gene P. Gardner - ----------------------------------- Gene P. Gardner, Director STATE OF KENTUCKY ) ) ss. COUNTY OF JEFFERSON) On this 6th day of March 1996, 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 14 EXHIBIT 27 FINANCIAL DATA SCHEDULE
UT 1,000 YEAR DEC-31-1995 JAN-01-1995 DEC-31-1995 PER-BOOK 1,663,918 760 267,371 47,441 0 1,979,490 424,334 (226) 181,049 605,157 0 95,328 646,845 0 0 0 16,000 0 0 0 616,160 1,979,490 723,463 47,524 554,613 602,137 121,326 3,776 125,102 41,918 83,184 6,311 76,873 89,000 41,259 198,600 0 0 Includes Common Stock Expense of $836. Represents unrealized loss on marketable securities, net of income taxes.
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